Company Quick10K Filing
Quick10K
Transcontinental Gas Pipe Line Company
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
8-K 2018-08-22 Regulation FD, Exhibits
8-K 2018-08-10 Leave Agreement, Off-BS Arrangement
8-K 2018-07-13 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-03-15 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-03-08 Other Events, Exhibits
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WSCC Waterside Capital
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JANL Janel
FALC Falconstor Software
FPVD Force Protection Video Equipment
TGPL 2018-12-31
Part 1
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 14. Principal Accounting Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
EX-31.1 tgpl_20181231xex-311.htm
EX-31.2 tgpl_20181231xex-312.htm
EX-32 tgpl_20181231xex-32.htm

Transcontinental Gas Pipe Line Company Earnings 2018-12-31

TGPL 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 tgpl_20181231x10k.htm 10-K Document

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number 1-7584
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
(Exact Name of Registrant as Specified in Its Charter)
Delaware
 
74-1079400
(State or Other Jurisdiction of Incorporation or Organization)

 
(I.R.S. Employer Identification No.)

 
 
 
2800 Post Oak Boulevard, Houston, Texas

 
77056
(Address of Principal Executive Offices)
 
(Zip Code)
713-215-2000
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  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 every Interactive Data File required to be submitted 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
 
Accelerated filer  ¨
 
Non-accelerated filer  þ
 
Smaller reporting company ¨
 
Emerging growth company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
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
 
 
 
Page
 
 
 
Item 1.
 
Item 1A.
 
Item 1B.
 
Item 2.
 
Item 3.
 
Item 4.
 
 
 
 
Item 5.
 
Item 6.
 
Item 7.
 
Item 7A.
 
Item 8.
 
Item 9.
 
Item 9A.
 
Item 9B.
 
 
 
 
Item 10.
 
 
Item 11.
 
 
Item 12.
 
 
Item 13.
 
 
Item 14.
 
 
 
 
Item 15.
 
Item 16.
 

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DEFINITIONS
We use the following gas measurements in this report:
Bcf – means billion cubic feet.
Mdth – means thousand dekatherms.
Mdth/d – means thousand dekatherms per day.
MMdth – means million dekatherms.

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PART 1
Item 1. Business
In this report, Transcontinental Gas Pipe Line Company, LLC (Transco) is at times referred to in the first person as “we”, “us” or “our”.

Transco is indirectly owned by The Williams Companies, Inc. (Williams), a publicly traded Delaware corporation. Prior to August 10, 2018, we were indirectly owned by Williams Partners L.P. (WPZ), a Delaware limited partnership which was consolidated by Williams. On August 10, 2018, Williams acquired all of the outstanding common units of WPZ held by others, merged WPZ into Williams (WPZ Merger), and Williams continued as the surviving entity.
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 an approximate 45 percent 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, 2018, our natural gas pipeline, which extends from Texas to New York, had a system-wide delivery capacity totaling approximately 16.7 MMdth of gas per day. During 2018, we completed two fully-contracted expansions, which added more than 1.75 MMdth of firm transportation capacity per day to our pipeline. The system is comprised of approximately 9,900 miles of mainline and branch transmission pipelines, 55 compressor stations, four underground storage fields and one liquefied natural gas (LNG) storage facility. Compression facilities at sea level rated capacity total approximately 2.2 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, 2018, our customers had stored in our facilities approximately 130 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 three largest customers in 2018 were Duke Energy Corporation, National Grid and The Southern Company, Inc., which accounted for approximately 9.5 percent, 9.1 percent and 8.1 percent, respectively, of our total operating revenues. Our firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of our business. Additionally, we offer interruptible transportation services under shorter-term agreements.
Our facilities are divided into eight rate zones. Five are located in the production area and three are located in the market area. Long-haul transportation is gas that is received in one of the production-area zones and delivered in a market-area zone. Market-area transportation is gas that is both received and delivered within market-area zones. Production–area transportation is gas that is both received and delivered within production–area zones.

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PIPELINE PROJECTS
The pipeline projects listed below were either completed during 2018 or are significant future pipeline projects for which we have customer commitments. In 2019, we expect to invest capital of approximately $1.0 billion in pipeline projects.
Hillabee
The Hillabee Expansion Project involves an expansion of our existing natural gas transmission system from our Station 85 Pooling Point in Choctaw County, Alabama to a new interconnection with the Sabal Trail pipeline in Tallapoosa County, Alabama. The project is being constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. We placed a portion of Phase I into service on June 14, 2017, and we placed the remainder of Phase I into service on July 11, 2017. Phase I increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020. Together, the first two phases of the project are expected to increase capacity by 1,025 Mdth/d.
In March 2016, WPZ entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters. In accordance with the agreement, the member-sponsors paid WPZ an aggregate amount of $240 million in three equal installments as certain milestones of the project were met. WPZ received the first $80 million payment in March 2016, the second $80 million payment in September 2016 and the third $80 million payment in July 2017. Although the agreement was an obligation between WPZ and the member-sponsors, since the agreement is, in part, related to furthering the completion of the project, we recorded deferred revenue and recognized a non-cash distribution to our parent. This deferred revenue is assigned to our results of operations over the 25-year term of the capacity agreement with Sabal Trail.
Garden State
The Garden State Expansion Project involved an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from our Station 210 Pooling Point in New Jersey to a new interconnection on our Trenton Woodbury Lateral in Burlington County, New Jersey. We placed the initial phase of the project into service on September 9, 2017, and the remaining portion of the project was placed into service on March 23, 2018. The project increased capacity by 180 Mdth/d.
Atlantic Sunrise
The Atlantic Sunrise Project involved 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 our mainline as far south as our Station 85 Pooling Point in Choctaw County, Alabama. We placed a portion of the mainline project facilities into service on September 1, 2017, which increased capacity by 400 Mdth/d. We placed additional mainline facilities into service on June 1, 2018, which increased capacity by an additional 150 Mdth/d. We placed the full project into service on October 6, 2018. In total, the project increased capacity by 1,700 Mdth/d.
Gulf Connector
The Gulf Connector Expansion Project involved 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. We placed the project into service on January 4, 2019. The project increased capacity by 475 Mdth/d.
Northeast Supply Enhancement
The Northeast Supply Enhancement 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 in New York. On April 20, 2018, the New York State Department of Environmental Conservation (NYSDEC) denied, without prejudice, Transco's application for certain permits required for the project. We addressed the technical issues identified by NYSDEC and refiled our application on May 16, 2018. We plan to place the project into service in the fourth quarter of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.


4


Rivervale South to Market
The Rivervale South to Market Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on our North New Jersey Extension to our existing Central Manhattan meter station in New Jersey and our Station 210 Pooling Point in New Jersey. In August 2018, we received approval from the FERC for the project. We plan to place the project into service as early as the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 190 Mdth/d.
Gateway
The Gateway Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from PennEast Pipeline Company's proposed interconnection with our mainline south of Station 205 in New Jersey to our existing Ridgefield meter station in Bergen County, New Jersey and our existing Paterson meter station in Passaic County, New Jersey. In December 2018, we received approval from the FERC for the project. We plan to place the project into service as early as the first quarter of 2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 65 Mdth/d.
Southeastern Trail
The Southeastern Trail Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion's Cove Point Pipeline in Virginia to the Station 65 Pooling Point in Louisiana. We filed an application with the FERC in April 2018 for approval of the project. We plan to place the project into service in late 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 296 Mdth/d.
Leidy South
The Leidy South Project involves an expansion of our existing natural gas transmission system and an extension of our system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco's Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. We expect to file an application with the FERC in June 2019 for approval of the project. We plan to place the project into service in the second half of 2022, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582.4 Mdth/d.

RATE MATTERS
FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and accepted by the FERC before any changes can go into effect. We establish our rates primarily through the FERC's ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariff and FERC policy. 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. RP18-1126) On August 31, 2018, we filed a general rate case with the FERC for an overall increase in rates and to comply with the terms of the settlement in our prior rate case to file a rate case no later than August 31, 2018. On September 28, 2018, the FERC issued an order accepting and suspending our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing, except that rates for certain

5


services that were proposed as overall rate decreases were accepted, without suspension, to be effective October 1, 2018. The decreased rates will not be subject to refund but may be subject to decrease prospectively under Section 5 of the Natural Gas Act of 1938, as amended (NGA).
The rates we charge to our customers are subject to the rate-making policies of the FERC. These policies permit us to include in our cost-of-service an income tax allowance that includes a deferred income tax component. The Tax Cuts and Jobs Act signed into law on December 22, 2017 (Tax Reform), made significant changes to the U.S. federal income tax rules applicable to both individuals and entities, including among other things, a reduction in corporate federal income tax rates. Although we expect that the decreased federal income tax rates will require us to reduce our rates charged to customers in the future and as a result we recognized a regulatory liability as of the date of enactment of Tax Reform, the details of any regulatory implementation guidance remain uncertain.
On March 15, 2018, the FERC issued a revised policy statement (the March 15 Statement) in Docket No. PL17-1 regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit a MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the WPZ Merger is to allow us to continue to recover an income tax allowance in our cost of service rates.
On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these previously accumulated ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the March 15 Statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule, but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC's guidance on ADIT likely will be challenged by customers and state commission, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.
On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking in Docket No. RM18-11 proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the corporate income tax rate in Tax Reform and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule in the docket, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. FERC also clarified that a natural gas company organized as a pass-through entity all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax, and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in our rates. Our Docket No. RP18-1126 rate case filing (discussed above) reflects a tax allowance based on this clarification, and the FERC's September 28, 2018 order in that rate case proceeding finds that we are exempt from the FERC Form No. 501-G filing requirement established in Docket No. RM18-11.
On March 15, 2018, the FERC also issued a Notice of Inquiry in Docket No. RM18-12 seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that our future tariff-based rates collected may be adversely impacted.


6


REGULATION
FERC Regulation.
Our interstate transmission and storage activities are subject to regulation by the FERC under the NGA, and under the Natural Gas Policy Act of 1978, as amended, and as such, our rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and accounting, among other things, are subject to regulation. We hold certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of pipelines, facilities and properties for which certificates are required 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 approximately $1.3 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 owners or 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 current 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 that could exceed our expectations,” and “Environmental Matters” in Note 3 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, the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety Act), and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (PIPES Act), which regulate safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. The U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) administers federal pipeline safety laws.
Federal pipeline safety laws authorize PHMSA 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

7


foreign commerce. PHMSA 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, PHMSA performs pipeline safety inspections and has the authority to initiate enforcement actions.
Pipeline Integrity Regulations We have an enterprise-wide Gas Integrity Management Plan that we believe meets the 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 Plan 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 as defined by the 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 2019 associated with this program will be approximately $69 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 Williams and other Williams’ subsidiaries. (See Note 1 and Note 8 of Notes to Consolidated Financial Statements.)
Item 1A. Risk Factors
FORWARD-LOOKING STATEMENTS
The 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 (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.
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:

Our and our affiliates’ future credit ratings;

Amounts and nature of future capital expenditures;

Expansion and growth of our business and operations;

Expected in-service dates for capital projects;

Financial condition and liquidity;


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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 forward-looking statements include, among others, the following:
Availability of supplies, including lower than anticipated volumes from third parties and market demand;

Volatility of pricing including the effect of lower than anticipated energy commodity 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 timely execute our capital projects and other investment opportunities in accordance with our capital expenditure budget;

Our ability to successfully expand our facilities and operations;

Development and rate of adoption of alternative energy sources;

Availability of adequate insurance coverage and the impact of operational and development hazards and unforeseen interruptions;

The impact of existing and future laws and regulations (including but not limited to the Tax Cuts and Jobs Act of 2017), the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals and achieve favorable rate proceeding outcomes;

Our 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 and physical damage to our facilities;

Acts of terrorism, including cybersecurity threats, and related disruptions; and

9



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 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.
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 unforeseen interruptions.
Our operations are subject to all the risks and hazards typically associated with the transportation and storage of natural gas including, but not limited to:
Aging infrastructure and mechanical problems;

Damages to pipelines and pipeline blockages or other pipeline interruptions;

Uncontrolled releases of natural gas;

Operator error;

Damage caused by third party activity, such as operation of construction equipment;

Pollution and other environmental risks; and

Fires, blowouts, cratering and explosions.
Any 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.



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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 or are subject to termination. Upon expiration or termination of 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, demand, availability and margins for natural gas in our markets;

Whether the market will continue to support long-term firm contracts;

The effects of regulation on us, our customers and our contracting practices; and

The ability to understand our 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 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 turnbackof 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, Williams and its other affiliates, 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

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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, financial condition, results of operations, and cash flows.
Any significant decrease in supplies of natural gas in the supply basins we access or in demand for those supplies in the markets we serve 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. Localized low natural gas prices in one or more of our existing supply basins, whether caused by a lack of infrastructure or otherwise, could also result in depressed natural gas production in such basins and limit the supply of natural gas made available to us. 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, and 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, results of operations and cash flows.
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 prevent 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 prevents us from 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, results of operations, and cash flows.

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The operation of our businesses might be adversely affected by regulatory proceedings, 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, including those pertaining to financial assurances to be provided by our businesses in respect of potential asset decommissioning and abandonment activities, might be revised, reinterpreted or otherwise enforced in a manner which differs from prior regulatory action. New laws and regulations might also be adopted or become applicable to us, our customers or our business activities. If new laws or regulations are imposed relating to oil and gas extraction, or if additional or revised 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, our compliance costs could increase 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 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 or denials 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 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.

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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 U.S. Environmental Protection Agency (EPA) or the passage of new climate change laws or regulations could result in increased costs to operate and maintain our facilities, install new emissions controls on our facilities, or 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, 2018, our largest customer was Duke Energy Corporation, which accounted for approximately 9.5 percent of our operating 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, financial condition, results of operations, and cash flows.
We are exposed to the credit risk of our customers and counterparties and our credit risk management will not be able to completely 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 cannot completely 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. In a low commodity price environment certain of our customers could be negatively impacted 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 could 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, or 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 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, financial condition, results of operations, and cash flows.
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

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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 interconnection 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, financial condition, results of operations, 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. 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 face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.
We have experienced, and we anticipate that we will continue to face, opposition to the operation and expansion of our pipelines and facilities from governmental officials, environmental groups, landowners, tribal groups, local groups and other advocates. In some instances, we encounter opposition which disfavors hydrocarbon based energy supplies regardless of practical implementation or financial considerations. Opposition to our operation and expansion can take many forms, including the delay or denial of required governmental permits, organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation or expansion of our assets and business. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that delays or prevents the expansion of our business, that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could adversely affect our financial condition and results of operations.
We may not be able to grow or effectively manage our growth.
As part of our growth strategy, we engage in significant capital projects. We have a project lifecycle process and an 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. Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing, or treating pipelines and facilities, as well as the expansion of existing facilities. Additional risks associated with construction may include the inability to obtain rights-of-way, skilled labor, equipment, materials, permits 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;


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We 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;

Acquisitions 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

Acquisitions and capital projects may require substantial new capital, including 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 could have an adverse impact on our financial condition, results of operations, including the possible impairment of our assets, or cash flows.
Risks Related to Strategy and Financing
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.
Downgrades of our credit ratings 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. 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 credit ratings agencies.
Our ability to obtain credit in the future could be affected by Williams’ credit ratings.
Substantially all of Williams’ operations are conducted through its respective subsidiaries. Williams’ cash flows are substantially derived from loans, dividends and distributions paid to it by its subsidiaries. Due to our relationship with Williams, our ability to obtain credit will be affected by Williams’ credit ratings. If Williams were to experience a deterioration in its credit standing or financial condition, our access to capital and our ratings could be adversely affected. Any downgrading of a Williams credit rating could result in a downgrading of our credit rating. A downgrading of a Williams credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.
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, 2018, was $4.01 billion.
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 guarantee certain indebtedness, to make certain distributions during the continuation of an event of default and 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’ 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, among other things:
Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;


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Impair our ability to obtain additional financing in the future for working capital, capital expenditures, general limited liability company purposes, or other purposes;

Diminish our ability to withstand a continued or future downturn in our business or the economy generally;

Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, general limited liability company purposes, or other purposes; and

Limit 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”.
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 periodically been affected by concerns over U.S. fiscal and 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 manner described above.
Williams can exercise substantial control over our distribution policy and our business and operations and may do so in a manner that is adverse to our interests.
Because we are an indirect wholly-owned subsidiary of Williams, Williams 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.

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Williams 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 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 and conditions of service;

Certification and construction of new interstate pipeline 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.
We expect that certain aspects of Tax Reform, including regulatory liabilities relating to reduced corporate federal income tax rates, could adversely impact our financial condition and our future financial results.
Tax Reform made significant changes to the U.S. federal income tax rules applicable to both individuals and entities, including among other things, a reduction in corporate federal income tax rates. The rates we charge to our customers are subject to the rate-making policies of the FERC. These policies permit us to include in our cost-of-service an income tax allowance that includes a deferred income tax component. Although we expect the decreased federal income tax rates will require us to return amounts to certain customers through future rates and have recognized a regulatory liability, the details of any regulatory implementation guidance remain uncertain.


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Risks Related to Employees and Outsourcing of Support Activities
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 the 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, financial condition, results of operations, and cash flows.
A failure to attract and retain an appropriately qualified workforce could negatively impact our results of operations.
Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, or unavailability of contract labor may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with projects and ongoing operations. Williams’ failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate the businesses. If Williams is unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.
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 results of operations and financial condition.
Risks Related to Weather, Other Natural Phenomena and Business Disruption
Our assets and operations, as well as our customersassets 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, financial condition, results of operations, and cash flows.
Our business could be negatively impacted by acts of terrorism and related disruptions.
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 business, financial condition, results of operations, and cash flows.

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A breach of our information technology infrastructure, including a breach caused by a cybersecurity attack on us or third parties with whom we are interconnected, may interfere with the safe operation of our assets, result in the disclosure of personal or proprietary information, and harm our reputation.
We rely on our information technology infrastructure to process, transmit, and store electronic information, including information we use to safely operate our assets. In addition to the oversight of our business provided by our Management Committee, the Williams’ Board of Directors has oversight responsibility with regard to enterprise-wide assessment of the major risks inherent in its businesses including cybersecurity risks. Accordingly, the Williams’ Board of Directors reviews management’s efforts to address and mitigate such risks, including the establishment and implementation of policies to address cybersecurity threats. We have invested, and expect to continue to invest, significant time, manpower and capital in our information technology infrastructure. However, 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. While we believe that we maintain appropriate information security policies, practices, and protocols, we regularly 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 face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists”, or private individuals. We face the threat of theft and misuse of sensitive data and information, including customer and employee information. We 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. We also are subject to cybersecurity risks arising from the fact that our business operations are interconnected with third parties, including third-party pipelines, other facilities and our contractors and vendors. In addition, the breach of certain business systems could affect our ability to correctly record, process and report financial 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 or destruction of our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability, the loss of contracts, the imposition of significant costs associated with remediation and litigation, heightened regulatory scrutiny, increased insurance costs, and have a material adverse effect on our operations, financial condition, results of operations, and cash flows.
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 additional information called for by this item is provided in “Item 8. Financial Statements and Supplementary Data – Notes to Consolidated Financial Statements – Note 3. Contingent Liabilities and Commitments”.
Item 4. Mine Safety Disclosures
Not applicable.

20


PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
We are indirectly owned by Williams.
Distributions totaling $490 million were declared and paid by us to our parent during the year ended December 31, 2018. An additional distribution of $176 million was declared and paid by us to our parent in January 2019. Distributions totaling $430 million were declared and paid by us to our parent during the year ended December 31, 2017. During July 2017, we recognized a non-cash distribution to our parent of $240 million.
In the year ended December 31, 2018, our parent made contributions totaling $340 million to us to fund a portion of our expenditures for additions to property, plant and equipment. In the year ended December 31, 2017, our parent made contributions to us totaling $410 million.
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. generally accepted accounting principles. The aggregate amount of regulatory assets reflected in the Consolidated Balance Sheet is $385.2 million at December 31, 2018. The aggregate amount of regulatory liabilities reflected in the Consolidated Balance Sheet is $1,032.0 million at December 31, 2018. A summary of regulatory assets and liabilities is included in Note 10 of Notes to Consolidated Financial Statements.

21


In December 2017, Tax Reform was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent. Rates charged to our customers are subject to the rate-making policies of the FERC, which have historically permitted the recovery of an income tax allowance that includes a deferred income tax component. As a result of the reduced income tax rate from Tax Reform and the collection of historical rates that reflected historical federal income tax rates, we expect that we will be required to return amounts to certain customers through future rates and have accordingly established a regulatory liability totaling $450.2 million and $471.1 million, respectively, as of December 31, 2018 and December 31, 2017. The timing and actual amount of such return will be subject to the outcome of the rate case proceeding filed in Docket No. RP18-1126.
Impairment 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 the assets to the carrying value of the assets to determine whether an impairment has occurred.
In December 2010 we detected a leak in one of the seven underground natural gas storage 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 operating problems at two other caverns constructed at about the same time, we determined that the four caverns should be retired, which was completed in 2014. In addition, further studies have indicated the need for capital improvements over the next several years of the remaining three caverns. As a result, we performed an assessment of our Eminence storage field for impairment as of December 31, 2018. The carrying value at that date was $103 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 undiscounted cash flows of Eminence exceeded its carrying value, and thus no impairment loss was recognized in 2018. If our estimates of revenues were to significantly decrease, it could result in an impairment of this asset.
Results of Operations
Analysis of Financial Results
This analysis discusses financial results of our operations for the years 2018 and 2017. 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.
2018 COMPARED TO 2017
Operating Income and Net Income
Operating Income for 2018 was $826.3 million compared to $153.9 million for 2017. The increase in Operating Income of $672.4 million (436.9 percent) was primarily due to a decrease in Operating Costs and Expenses in 2018 compared to 2017, as discussed below, and higher Natural gas transportation, Natural gas sales and Other revenues in 2018 compared to 2017, as discussed below. Net Income for 2018 was $741.1 million compared to $55.7 million for 2017. The increase in Net Income of $685.4 million (1,230.5 percent) was mostly attributable to an increase in Operating Income, as discussed below, and a favorable change 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.

22


Operating Revenues
Natural gas sales increased $28.7 million (29.0 percent) to $127.8 million for 2018 when compared to 2017. The increase was due to $26.5 million of higher cash-out sales and $2.2 million of higher system management gas sales. Cash-out sales and system management gas sales are offset in our costs of natural gas sold and therefore had no impact on our operating income or results of operations.
Natural gas transportation for 2018 was $1,784.8 million compared to $1,531.8 million for 2017. The $253.0 million (16.5 percent) increase was primarily attributable to:
$240.5 million increase in transportation reservation revenues related to new incremental projects primarily attributable to:
$111.5 million from our Atlantic Sunrise project placed in partial service in September 2017, and fully in service in October 2018;
$36.3 million from our Virginia Southside Phase II project placed in service in December 2017;
$28.7 million from our Dalton project placed in partial service in April 2017, and fully in service in August 2017;
$22.0 million from our Hillabee project Phase I placed in partial service in June 2017, and fully in service in July 2017;
$18.7 million from our Garden State project placed in partial service in September 2017, and fully in service in March 2018;
$17.7 million from our New York Bay project placed in service in October 2017; and
$4.9 million from our Gulf Trace project placed in service in February 2017.
$14.0 million higher recoveries of 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; and
$10.0 million higher commodity revenue.
Partially offset by $6.0 million lower revenues related to Docket No. RP18-1126 rate decreases effective October 1, 2018.
Other for 2018 increased $3.8 million (55.9 percent) compared to 2017 primarily attributable to the amortization of deferred revenue on the Hillabee project.
Operating Costs and Expenses
Excluding the Cost of natural gas sales, which is directly offset in revenues, our operating expenses decreased approximately $416.2 million (27.3 percent) from the comparable period in 2017. This decrease was primarily attributable to:
A $492.0 million (104.4 percent) decrease in Regulatory charges (credit) resulting from Tax Reform (Note 1);
A $2.6 million (0.6 percent) decrease in Operation and maintenance costs mostly due to $12.6 million lower costs related to pipeline integrity, general maintenance and other testing on our pipeline partly offset by $10.3 million higher employee labor and related benefits costs;
Partially offset by a $48.5 million (15.2 percent) increase in Depreciation and amortization costs primarily related to additional assets placed into service;
A $19.1 million (97.4 percent) increase in Cost of natural gas transportation costs primarily resulting from $14.1 million higher electric power costs and $5.1 million higher fuel costs;
A $7.5 million (4.1 percent) increase in Administrative and general costs primarily due to higher allocated corporate expenses; and
A $1.9 million (2.9 percent) increase in Taxes-other than income taxes primarily due to higher ad valorem taxes as a result of additional assets placed into service.


23


Other (Income) and Other Expenses
Other (Income) and Other Expenses in 2018 had a favorable change of $13.0 million (13.2 percent) over 2017. This favorable change was primarily attributable to:
A $35.9 million (114.3 percent) favorable change in Miscellaneous other (income) expenses, net primarily related to the absence of a regulatory charge associated with Tax Reform for the effects of deferred taxes on equity funds used during construction recorded in 2017;
A $24.3 million (26.4 percent) favorable change in Allowance for equity and borrowed funds used during construction (AFUDC) associated with capital expenditures on projects.
A $7.3 million (117.7 percent) favorable change in Equity in (earnings) loss of unconsolidated affiliates primarily related to a regulatory charge associated with establishing a regulatory liability resulting from Tax Reform recorded in 2017;
A $4.1 million (117.1 percent) favorable change in Interest income - affiliate primarily due to higher intercompany interest rates; and
Partially offset by $59.3 million (37.3 percent) unfavorable Interest expense - other primarily due to $26.4 million associated with our debt issuance in March 2018 and $33.1 million associated with other financing obligations (See Note 4 of Notes to Consolidated Financial Statements).
Station 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 station and the facility was not operational. The incident was related to maintenance work being performed on the slug catcher at the station. Four contractor employees were killed in the incident and others were injured.
In responding to the incident, we cooperated 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 (PHMSA). On July 29, 2016, PHMSA issued a Notice of Probable Violation (NOPV), which includes a $1.6 million proposed civil penalty to us in connection with the incident. This penalty was accrued in the second quarter of 2016 and would not be covered by our insurance policies. We filed a response to the NOPV on August 25, 2016, and on July 14, 2017, PHMSA held a hearing on the NOPV. On December 20, 2018, the PHMSA issued a Final Order, which made findings of violation, reduced the civil penalty to $1.4 million, and specified actions that need to be taken by us to comply with pipeline safety regulations.
The incident did not cause any rupture of the gas pipeline or any damage to the building containing the compressor engines. In anticipation of the planned 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 was restored to service in early 2016 after repairs were made to the facilities damaged in the incident.
We, with the insurer of one of our contractors, have settled several claims against us for wrongful death and personal injury. In addition, we are a defendant in other lawsuits seeking damages for wrongful death, personal injury and property damages. We believe it is reasonably possible that losses will be incurred on some lawsuits. However, in management's judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations or cash flows. While we also have claims for indemnification, we continue to believe that it is probable that any ultimate losses incurred will be covered by our contractors' insurance and our insurance.
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

24


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 Williams, collection of advances to Williams, accessing capital markets, and, if required, borrowings under the credit facility described below and advances from Williams.
We may raise capital through private debt offerings, as well as offerings registered pursuant to offering-specific registration statements. Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets. On March 15, 2018, we completed a private placement of $400 million of 4.0 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 . We used the net proceeds from the offering to repay indebtedness, including our $250 million of 6.05 percent notes due upon their maturity on June 15, 2018, and for general corporate purposes, including the funding of capital expenditures. The notes issued in March 15, 2018 were the subject of a registration rights agreement. In the third quarter of 2018, we completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act.
We, along with Williams and Northwest Pipeline LLC, are co-borrowers under a $4.5 billion unsecured credit facility. Total letter of credit capacity available to Williams under the credit facility is $1.0 billion. We may borrow up to $500 million under the credit facility to the extent not otherwise utilized by Williams and Northwest Pipeline LLC. See Note 4 of Notes to Consolidated Financial Statements for further discussion of the credit facility.
We are a participant in Williams's cash management program, and we make advances to and receive advances from Williams. At December 31, 2018, our advances to Williams totaled approximately $33.0 million. These advances are represented by demand notes. The decrease in 2018 of these advances primarily resulted from the use of funds for capital expenditures.
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 2019 capital expenditures will be approximately $1.0 billion for expansion projects and $0.2 billion for maintenance projects, the majority of the amount is considered nondiscretionary due to legal, regulatory, and/or contractual requirements.

25


Item 7A. Quantitative and Qualitative Disclosures About Market Risk
At December 31, 2018, 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, 2018. The table presents principal cash flows and weighted-average interest rates by expected maturity dates.
 
December 31, 2018
Expected Maturity Date
 
2019
 
2020
 
2021
 
2022
 
(Dollars in millions)
Long-term debt, excluding other financing obligation:
 
 
 
 
 
 
 
Fixed rate
$

 
$

 
$

 
$

Interest rate
5.87
%
 
5.87
%
 
5.87
%
 
5.87
%
 
 
 
 
 
 
 
 
Other financing obligation:
 
 
 
 
 
 
 
Fixed rate
$
15

 
$
17

 
$
19

 
$
21

Interest rate
9.93
%
 
9.93
%
 
9.93
%
 
9.92
%
 
 
 
 
 
 
 
 
December 31, 2018
Expected Maturity Date
 
2023
 
Thereafter
 
Total
 
Fair Value
 
(Dollars in millions)
Long-term debt, excluding other financing obligation:
 
 
 
 
 
 
 
Fixed rate
$

 
$
2,983

 
$
2,983

 
$
3,136

Interest rate
5.87
%
 
4.95
%
 
 
 
 
 
 
 
 
 
 
 
 
Other financing obligation:
 
 
 
 
 
 
 
Fixed rate
$
23

 
$
972

 
$
1,067

 
$
1,649

Interest rate
9.92
%
 
9.78
%
 
 
 
 


26


Item 8. Financial Statements and Supplementary Data
 

27


Report of Independent Registered Public Accounting Firm

To The Management Committee and Member of Transcontinental Gas Pipe Line Company, LLC

Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheet of Transcontinental Gas Pipe Line Company, LLC (the Company) as of December 31, 2018 and 2017, the related consolidated statements of comprehensive income, member’s equity, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting 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.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company's auditor since 1995.

Houston, Texas
February 21, 2019


28


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)
 
 
 
Years Ended December 31,
 
 
2018
 
2017
 
2016
Operating Revenues:
 
 
 
 
 
 
Natural gas sales
 
$
127,821

 
$
99,100

 
$
86,720

Natural gas transportation
 
1,784,794

 
1,531,778

 
1,397,341

Natural gas storage
 
136,666

 
137,348

 
122,555

Other
 
10,600

 
6,779

 
9,519

Total operating revenues
 
2,059,881

 
1,775,005

 
1,616,135

 
 
 
 
 
 
 
Operating Costs and Expenses:
 
 
 
 
 
 
Cost of natural gas sales
 
127,821

 
99,100

 
86,720

Cost of natural gas transportation
 
38,749

 
19,589

 
19,689

Operation and maintenance
 
399,293

 
401,871

 
316,989

Administrative and general
 
189,588

 
182,121

 
168,759

Depreciation and amortization
 
366,566

 
318,058

 
307,707

Taxes — other than income taxes
 
67,537

 
65,612

 
60,119

Regulatory charge (credit) resulting from Tax Reform (Note 1)
 
(20,867
)
 
471,096

 

Other expense, net
 
64,918

 
63,644

 
57,064

Total operating costs and expenses
 
1,233,605

 
1,621,091

 
1,017,047

 
 
 
 
 
 
 
Operating Income
 
826,276

 
153,914

 
599,088

 
 
 
 
 
 
 
Other (Income) and Other Expenses:
 
 
 
 
 
 
Interest expense - affiliate
 
60

 
60

 
60

                           - other
 
218,126

 
158,814

 
151,234

Interest income - affiliate
 
(7,606
)
 
(3,507
)
 
(2,201
)
                           - other
 
(3,448
)
 
(2,782
)
 
(2,185
)
Allowance for equity and borrowed funds used during construction (AFUDC)
 
(116,347
)
 
(92,013
)
 
(68,964
)
Equity in (earnings) loss of unconsolidated affiliates
 
(1,068
)
 
6,188

 
(5,914
)
Miscellaneous other (income) expenses, net
 
(4,520
)
 
31,426

 
3,683

Total other (income) and other expenses
 
85,197

 
98,186

 
75,713

 
 
 
 
 
 
 
Net Income
 
741,079

 
55,728

 
523,375

 
 
 
 
 
 
 
Other comprehensive income:
 
 
 
 
 
 
Equity interest in unrealized gain on interest rate hedges (includes $(143), $103, and $167 for the years ended December 31, 2018, 2017, and 2016, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses (gains) on interest rate hedges)
 
197

 
327

 
41

 
 
 
 
 
 
 
Comprehensive Income
 
$
741,276

 
$
56,055

 
$
523,416

See accompanying notes.


29


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
 
 
 
December 31,
 
 
2018
 
2017
ASSETS
 
 
 
 
 
 
 
 
 
Current Assets:
 
 
 
 
Cash
 
$

 
$

Receivables:
 
 
 
 
Trade
 
190,833

 
167,928

Affiliates
 
1,018

 
1,109

Advances to affiliate
 
33,034

 
395,247

Other
 
10,365

 
2,494

Transportation and exchange gas receivables
 
4,515

 
3,205

Inventories:
 
 
 
 
Gas in storage, at original cost
 
875

 
790

Gas available for customer nomination, at average cost
 
25,767

 
1,850

Materials and supplies, at average cost
 
36,563

 
37,387

Regulatory assets
 
95,770

 
97,149

Other
 
12,574

 
12,508

Total current assets
 
411,314

 
719,667

 
 
 
 
 
Investments, at cost plus equity in undistributed earnings
 
26,520

 
28,505

 
 
 
 
 
Property, Plant and Equipment:
 
 
 
 
Natural gas transmission plant
 
15,908,878

 
13,771,183

Less-Accumulated depreciation and amortization
 
4,147,729

 
3,859,520

Total property, plant and equipment, net
 
11,761,149

 
9,911,663

 
 
 
 
 
Other Assets:
 
 
 
 
Regulatory assets
 
289,479

 
276,315

Other
 
167,490

 
141,786

Total other assets
 
456,969

 
418,101

 
 
 
 
 
Total assets
 
$
12,655,952

 
$
11,077,936

(continued)





See accompanying notes.

30


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
 
 
 
December 31,
 
 
2018
 
2017
LIABILITIES AND MEMBER’S EQUITY
 
 
 
 
 
 
 
Current Liabilities:
 
 
 
 
Payables:
 
 
 
 
Trade
 
$
201,350

 
$
444,021

Affiliates
 
50,727

 
43,420

Cash overdrafts
 
25,561

 
25,132

Transportation and exchange gas payables
 
5,973

 
2,121

Accrued liabilities:
 
 
 
 
Property and other taxes
 
15,428

 
12,843

Interest
 
62,066

 
49,900

Regulatory liabilities
 
5,097

 
16,350

Customer deposits
 
36,400

 
15,754

Customer advances
 
36,642

 
44,689

Asset retirement obligations
 
45,714

 
13,676

Other
 
22,134

 
20,390

Long-term debt due within one year
 
15,419

 
251,430

       Total current liabilities
 
522,511

 
939,726

 
 
 
 
 
Long-Term Debt
 
3,998,988

 
2,191,576

 
 
 
 
 
Other Long-Term Liabilities:
 
 
 
 
Asset retirement obligations
 
348,609

 
350,280

Regulatory liabilities
 
1,026,892

 
990,702

Advances for construction costs
 
211

 
426,771

Deferred revenue
 
226,164

 
236,729

Other
 
3,977

 
4,828

Total other long-term liabilities
 
1,605,853

 
2,009,310

 
 
 
 
 
Contingent Liabilities and Commitments (Note 3)
 

 

 
 
 
 
 
Member’s Equity:
 
 
 
 
Member’s capital
 
4,428,499

 
4,088,499

Retained earnings
 
2,099,567

 
1,848,488

Accumulated other comprehensive income
 
534

 
337

Total member’s equity
 
6,528,600

 
5,937,324

 
 
 
 
 
Total liabilities and member’s equity
 
$
12,655,952

 
$
11,077,936

See accompanying notes.


31


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF MEMBER’S EQUITY
(Thousands of Dollars)
 
 
 
Years Ended December 31,
 
 
2018
 
2017
 
2016
Member's Capital:
 
 
 
 
 
 
Balance at beginning of period
 
$
4,088,499

 
$
3,678,499

 
$
3,176,499

Cash contributions from parent
 
340,000

 
410,000

 
502,000

Balance at end of period
 
4,428,499

 
4,088,499

 
3,678,499

Retained Earnings:
 
 
 
 
 
 
Balance at beginning of period
 
1,848,488

 
2,462,760

 
2,379,385

Net income
 
741,079

 
55,728

 
523,375

Cash distributions to parent
 
(490,000
)
 
(430,000
)
 
(440,000
)
Non-cash distribution to parent
 

 
(240,000
)
 

Balance at end of period
 
2,099,567

 
1,848,488

 
2,462,760

Accumulated Other Comprehensive Income (Loss):
 
 
 
 
 
 
Balance at beginning of period
 
337

 
10

 
(31
)
Equity interest in unrealized gain on interest rate hedge
 
197

 
327

 
41

Balance at end of period
 
534

 
337

 
10

 
 
 
 
 
 
 
Total Member's Equity
 
$
6,528,600

 
$
5,937,324

 
$
6,141,269














See accompanying notes.


32


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
 
 
 
Years Ended December 31,
 
 
2018
 
2017
 
2016
Cash flows from operating activities:
 
 
 
 
 
 
Net income
 
$
741,079

 
$
55,728

 
$
523,375

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
366,566

 
318,058

 
307,707

Allowance for equity funds used during construction (equity AFUDC)
 
(87,111
)
 
(69,653
)
 
(56,468
)
Regulatory charge (credit) resulting from Tax Reform (Note 1)
 
(20,867
)
 
471,096

 

Equity in (earnings) loss of unconsolidated affiliates
 
(1,068
)
 
6,188

 
(5,914
)
Distributions from unconsolidated affiliates
 
3,250

 
8,036

 
8,631

Changes in operating assets and liabilities:
 
 
 
 
 
 
Receivables — affiliates
 
91

 
(620
)
 
595

— trade and other
 
(30,776
)
 
(26,107
)
 
5,941

Transportation and exchange gas receivable
 
(1,310
)
 
(1,378
)
 
600

Regulatory assets - current
 
1,379

 
(10,090
)
 
(7,484
)
Regulatory assets - non-current
 
(8,605
)
 
(10,761
)
 
(271
)
Inventories
 
(23,178
)
 
15,182

 
1,632

Payables — affiliates
 
7,307

 
12,514

 
(10,909
)
— trade
 
(35,869
)
 
(9,823
)
 
29,375

Accrued liabilities
 
29,740

 
(29,651
)
 
74,759

Asset retirement obligations - non-current
 
34,075

 
103,105

 
31,114

Asset retirement obligation - removal costs
 
(9,416
)
 
(4,578
)
 
(4,911
)
Deferred revenue
 
(10,565
)
 
(4,542
)
 

Other, net
 
21,570

 
4,117

 
32,080

Net cash provided by operating activities
 
976,292

 
826,821

 
929,852

 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
Proceeds from long-term debt
 
993,440

 

 
998,250

Proceeds from other financing obligations
 
50,269

 

 

Retirement of long-term debt
 
(250,000
)
 

 
(200,000
)
Payments on other financing obligations
 
(3,705
)
 
(486
)
 

Payments for debt issuance costs
 
(10,148
)
 
(13
)
 
(8,381
)
Cash distributions to parent
 
(490,000
)
 
(430,000
)
 
(440,000
)
Cash contributions from parent
 
340,000

 
410,000

 
502,000

Net cash provided by (used in) financing activities
 
629,856

 
(20,499
)
 
851,869

(continued)



See accompanying notes.

33


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
 
 
 
Years Ended December 31,
 
 
2018
 
2017
 
2016
Cash flows from investing activities:
 
 
 
 
 
 
Property, plant and equipment additions, net of equity AFUDC*
 
$
(2,326,672
)
 
$
(1,576,611
)
 
$
(1,213,969
)
Contributions and advances for construction costs
 
408,912

 
425,397

 
216,447

Disposal of property, plant and equipment, net
 
(26,469
)
 
(49,090
)
 
(12,529
)
Advances to affiliate, net
 
362,213

 
416,446

 
(747,085
)
Purchase of ARO Trust investments
 
(51,793
)
 
(57,099
)
 
(70,901
)
Proceeds from sale of ARO Trust investments
 
27,661

 
31,435

 
44,195

Proceeds from insurance
 

 
3,200

 
2,121

Net cash used in investing activities
 
(1,606,148
)
 
(806,322
)
 
(1,781,721
)
 
 
 
 
 
 
 
Increase (decrease) in cash
 

 

 

Cash at beginning of period
 

 

 

Cash at end of period
 
$

 
$

 
$

 
 
 
 
 
 
 
____________________________
 
 
 
 
 
 
*   Increase to property, plant and equipment, net of equity AFUDC
 
$
(2,085,888
)
 
$
(1,784,254
)
 
$
(1,200,696
)
Changes in related accounts payable and accrued liabilities
 
(240,784
)
 
207,643

 
(13,273
)
Property, plant and equipment additions, net of equity AFUDC
 
$
(2,326,672
)
 
$
(1,576,611
)
 
$
(1,213,969
)
 
 
 
 
 
 
 
Supplemental disclosures of cash flow information:
 
 
 
 
 
 
Cash paid during the year for:
 
 
 
 
 
 
Interest (exclusive of amount capitalized)
 
$
168,418

 
$
136,439

 
$
103,391

Income taxes
 
632

 
2,089

 
828





See accompanying notes.


34


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Corporate Structure and Control
In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and, unless the context otherwise requires, all of our majority-owned subsidiaries) is at times referred to in the first person as “we,” “us” or “our.”
Transco was indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which was consolidated by The Williams Companies, Inc. (Williams). On August 10, 2018, Williams completed a merger with WPZ, pursuant to which Williams acquired all of the publicly held outstanding common units of WPZ in exchange for shares of Williams' common stock (WPZ Merger). Williams continued as the surviving entity. Transco is now indirectly owned by Williams.
Transco is a single member limited liability company, and as such, single member losses are limited to the amount of its investment.
Related Party Transaction
A former member of Williams' Board of Directors, who was elected in 2013 and resigned during 2016, is also the current chairman, president, and chief executive officer of Public Service Enterprise Group, an energy services company that is a customers of ours. 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.
Nature of Operations
We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the 12 southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, Washington D.C., Maryland, North Carolina, New York, New Jersey and Pennsylvania.
Regulatory Accounting
We are regulated by the Federal Energy Regulatory Commission (FERC). The Accounting Standards Codification (ASC) Regulated Operations (Topic 980), provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations (ARO), 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.
In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent. We have recognized a regulatory liability to reflect the probable return to certain customers through future rates of the future decrease in income taxes payable associated with Tax Reform. In determining the estimated liability that we currently believe is probable of return to certain

35


customers through future rates, we considered the mix of services provided by us, taking into consideration that certain of these services are provided under contractually based rates, in lieu of recourse-based rates, that are designed to recover the cost of providing those services, with no expected future rate adjustment for the term of those contracts. The liability was recorded in December 2017 through a regulatory charge to operating income of $471.1 million, this regulatory charge was reduced by $20.9 million in 2018 mostly due to an updated weighted average state income tax rate. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service.
Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity in (earnings) loss of unconsolidated affiliates on our Consolidated Statement of Comprehensive Income has been reduced by $2.0 and $10.3 million in 2018 and 2017, respectively, related to our proportionate share of the associated regulatory charges.
Our regulatory asset associated with the effects of deferred taxes on equity funds used during construction was also impacted by Tax Reform and was reduced by $0.9 million and $32.7 million in 2018 and 2017, respectively, through a charge to Miscellaneous other (income) expenses, net on our Consolidated Statement of Comprehensive Income.
Basis of Presentation
Williams’ acquisition of Transco Energy Company and its subsidiaries, including us, in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At December 31, 2018, the remaining property, plant and equipment allocation was approximately $0.6 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.
Principles of Consolidation
The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of December 31, 2018 and December 31, 2017 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 $3.2 million, $8.0 million, and $8.6 million in 2018, 2017 and 2016, 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; 6) asset retirement obligations; and 7) regulatory deferred taxes.
Revenue Recognition (subsequent to the adoption of ASC 606)
Our customers are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical power generators.
A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct

36


if the product or service is separately identifiable from other items in the integrated package of services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. Service revenue contracts contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.
Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. As a rate-regulated entity applying Topic 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of Accounting Standards Update (ASU) 2014-09, Revenues from Contracts with Customers (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset.
Service Revenues
We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or as negotiated with our customers, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations include the following:
Firm transportation or storage under firm transportation and storage contracts - an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;
Interruptible transportation and storage under interruptible transportation and storage contracts - an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.
In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.
We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

37


Product Sales
In the course of providing transportation services to customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs. Revenue is recognized from the sale of natural gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note).
Contract Liabilities
Our contract liabilities consist of advance payments from customers, which include prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily straight-line over the remaining contractual service periods, and are classified as current or non-current according to when such amounts are expected to be recognized. Current and non-current contract liabilities are included within Accrued Liabilities and Other Long-Term Liabilities - Deferred revenue, respectively, in our Consolidated Balance Sheet.
Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer and when the customer pays for those goods or services and the prevailing interest rates. We have assessed our contracts and determined none of our contracts contain a significant financing component.
Revenue Recognition (prior to the adoption of ASC 606)
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 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
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

38


conditions and operations. 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, 2018, 2017 and 2016 are as follows:
 
Category of Property
 
2018-2016
 
 
 
Gathering facilities
 
1.35% - 2.50%
Storage facilities
 
2.10% -  2.25%
Onshore transmission facilities
 
2.61%  -  5.00%
Offshore transmission facilities
 
1.20%  -  1.20%
We record a liability and increase the basis in the underlying asset for the present value of each expected future 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
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.



39


Allowance for Funds Used During Construction
Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $29.2 million, $22.3 million and $12.5 million, for 2018, 2017 and 2016, respectively. The allowance for equity funds was $87.1 million, $69.7 million, and $56.5 million, for 2018, 2017 and 2016, respectively.
Income Taxes
We are a natural gas company organized as a pass-through entity and our taxable income or loss is consolidated on the federal income tax return of our parent, Williams. We generally are treated as a pass-through entity for state and local income tax purposes, and those taxes are generally borne on a consolidated basis by Williams. Net income for financial statement purposes may differ significantly from taxable income of Williams as a result of differences between the tax basis and financial reporting basis of assets and liabilities.
Accounts Receivable and Allowance for Doubtful Receivables
Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. 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, 2018 and 2017. We utilize the average cost method of accounting for gas imbalances.
Deferred Cash Out
Most transportation imbalances are settled in cash on a monthly basis (cash-out). In accordance with our tariff, revenues received from the cash-out of transportation imbalances in excess of costs incurred are deferred and offset by the deferral of costs incurred in excess of revenues received. At the end of each annual August through July reporting period, if the cumulative revenues received exceed the costs incurred, the over recovered amounts are refunded. If the

40


cumulative revenues received are less than the costs incurred, the net under recovered amounts are carried forward and offset against any future net over recoveries that may occur in a subsequent annual reporting period.
Gas Inventory
We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. At December 31, 2018 and 2017, Gas in Storage, at LIFO, was zero. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost.
Materials and Supplies Inventory
All inventories are stated at average cost. 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, 2018 and 2017.
Contingent Liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.
Pension and Other Postretirement Benefits
We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 7.) 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 and Adopted
Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). Among other things, ASU 2016-15 permits an accounting policy election to classify distributions received from equity-method investees using either the cumulative earnings approach or the nature of distribution approach. We have elected to apply the nature of distribution approach and have retrospectively conformed the prior year presentation within the Consolidated Statement of Cash Flows in accordance with ASU 2016-15. For the periods ended December 31, 2017 and December 31, 2016, amounts previously presented as Return of capital from unconsolidated affiliates within Investing Activities are now presented as part of Distributions from unconsolidated affiliates within Operating Activities, resulting in an increase to Net cash provided by operating activities of $3.9 million and $2.8 million, respectively, with a corresponding reduction in Net cash used in investing activities.
In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes

41


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 became effective for interim and annual reporting periods beginning after December 15, 2017.
We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not completed as of that date. There was no cumulative effect adjustment to retained earnings upon initially applying ASC 606 for periods prior to January 1, 2018.
For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. As a result of the adoption of ASC 606, there are no changes to the timing of our revenue recognition or differences in the presentation in our consolidated financial statements from those under the previous revenue standard. (See Note 2.)
Accounting Standards Issued But Not Yet Adopted
In June 2016, the FASB issued ASU 2016-13 "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments" (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking "expected loss" model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The standard requires varying transition methods for the different categories of amendments. We do not expect ASU 2016-13 to have a significant impact on our financial statements.
In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and right-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases”.
In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements”(ASU 2018-11). Prior to ASU 2018-11, a modified retrospective transition was required for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. ASU 2018-11 allows entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. ASU 2018-11 also allows a practical expedient that permits lessors to not separate non-lease components from the associated lease component if certain conditions are present. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. We adopted ASU 2016-02 effective January 1, 2019.
We are substantially complete with our review of contracts to identify leases based on the modified definition of a lease and changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption of ASU 2016-02. We implemented a financial lease accounting system to assist management in the accounting for leases upon adoption. We are substantially complete with the implementation of ASU 2016-02 and believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our Balance Sheet for operating leases, which we estimate to be less than 3 percent of

42


total liabilities and total assets, respectively. We have also evaluated ASU 2016-02’s available practical expedients on adoption. We generally elected to adopt the practical expedients, which includes the practical expedient to not separate lease and non-lease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.
2. REVENUE RECOGNITION
Revenue by Category
Our revenue disaggregation by major service line includes Natural gas sales, Natural gas transportation, Natural gas storage, and Other, which are separately presented on the Consolidated Statement of Comprehensive Income.

Contract Liabilities
The following table presents a reconciliation of our contract liabilities:
 
December 31, 2018
 
(Thousands)
Balance at beginning of period
$
247,296

Payments received and deferred

Recognized in revenue
(10,566
)
Balance at end of period
$
236,730


The following table presents the amount of the contract liabilities balance as of December 31, 2018, expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:
 
(Thousands)
2019
$
10,566

2020
10,568

2021
10,566

2022
10,566

2023
10,566

Thereafter
183,898

Remaining Performance Obligations
The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2018. These primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes the variable consideration component for commodity charges. It also excludes consideration that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). As noted above, certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligation as of December 31, 2018, does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.

43


 
(Thousands)
2019
$
2,085,113

2020
1,956,772

2021
1,881,776

2022
1,520,358

2023
1,386,290

Thereafter
12,501,777

Total
$
21,332,086

Accounts Receivable
Receivables from contracts with customers are included within Receivables - Trade and Receivables - Affiliates and receivables that are not related to contracts with customers are included with Receivables - Advances to affiliate and Receivables - Other in our Consolidated Balance Sheet.
3. CONTINGENT LIABILITIES AND COMMITMENTS
Rate Matters
General rate case (Docket No. RP18-1126) On August 31, 2018, we filed a general rate case with the FERC for an overall increase in rates and to comply with the terms of the settlement in our prior rate case to file a rate case no later than August 31, 2018. On September 28, 2018, the FERC issued an order accepting and suspending our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing, except that rates for certain services that were proposed as overall rate decreases were accepted, without suspension, to be effective October 1, 2018. The decreased rates will not be subject to refund but may be subject to decrease prospectively under Section 5 of the Natural Gas Act of 1938, as amended.
Income tax matters On March 15, 2018, the FERC issued a revised policy statement (the March 15 Statement) in Docket No. PL17-1 regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit a MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the WPZ Merger is to allow us to continue to recover an income tax allowance in our cost of service rates.
On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these previously accumulated ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the March 15 Statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule, but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the fact of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC's guidance on ADIT likely will be challenged by customers and state commission, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.
On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking in Docket No. RM18-11 proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the corporate income tax rate in Tax Reform and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule in the docket, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. FERC also clarified

44


that a natural gas company organized as a pass-through entity all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax, and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in our rates. Our Docket No. RP18-1126 rate case filing (discussed above) reflects a tax allowance based on this clarification, and the FERC's September 28, 2018 order in that rate case proceeding finds that we are exempt from the FERC Form No. 501-G filing requirement established in Docket No. RM18-11.
On March 15, 2018, the FERC also issued a Notice of Inquiry in Docket No. RM18-12 seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that our future tariff-based rates collected may be adversely impacted.
Station 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 station and the facility was not operational. The incident was related to maintenance work being performed on the slug catcher at the station. Four contractor employees were killed in the incident and others were injured.
In responding to the incident, we cooperated 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 (PHMSA). On July 29, 2016, PHMSA issued a Notice of Probable Violation (NOPV), which includes a $1.6 million proposed civil penalty to us in connection with the incident. This penalty was accrued in the second quarter of 2016 and would not be covered by our insurance policies. We filed a response to the NOPV on August 25, 2016, and on July 14, 2017, PHMSA held a hearing on the NOPV. On December 20, 2018, the PHMSA issued a Final Order, which made findings of violation, reduced the civil penalty to $1.4 million, and specified actions that need to be taken by us to comply with pipeline safety regulations.
The incident did not cause any rupture of the gas pipeline or any damage to the building containing the compressor engines. In anticipation of the planned 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 was restored to service in early 2016 after repairs were made to the facilities damaged in the incident.
We, with the insurer of one of our contractors, have settled several claims against us for wrongful death and personal injury. In addition, we are a defendant in other lawsuits seeking damages for wrongful death, personal injury and property damages. We believe it is reasonably possible that losses will be incurred on some lawsuits. However, in management's judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations or cash flows. While we also have claims for indemnification, we continue to believe that it is probable that any ultimate losses incurred will be covered by our contractors' insurance and our insurance.
Environmental 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 $5 million to $7 million (including both expense and capital expenditures), measured on an undiscounted basis, and will substantially be spent over the next four to six years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures.

45


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, 2018, we had a balance of approximately $3.5 million for the expense portion of these estimated costs, $1.5 million recorded in Accrued liabilities and $2.0 million recorded in Other Long-Term Liabilities - Other in the Consolidated Balance Sheet. At December 31, 2017, we had a balance of approximately $4.0 million for the expense portion of these estimated costs, $1.8 million recorded in Accrued liabilities and $2.2 million recorded in Other Long-Term Liabilities - Other in the Consolidated Balance Sheet.
We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $5 million to $7 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Total property, plant and equipment, net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.
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.
Other Matters
Various other proceedings are pending against us and are considered incidental to our operations.
Summary
We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.
Other Commitments
Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $137 million at December 31, 2018.

46


4. DEBT, FINANCING ARRANGEMENTS AND LEASES
Long-Term Debt
At December 31, 2018 and 2017, long-term debt outstanding was as follows (in thousands): 
 
 
2018
 
2017
Debentures:
 
 
 
 
7.08% due 2026
 
$
7,500

 
$
7,500

7.25% due 2026
 
200,000

 
200,000

Total debentures
 
207,500

 
207,500

 
 
 
 
 
Notes:
 
 
 
 
6.05% due 2018
 

 
250,000

7.85% due 2026
 
1,000,000

 
1,000,000

4.0% due 2028
 
400,000

 

5.4% due 2041
 
375,000

 
375,000

4.45% due 2042
 
400,000

 
400,000

4.6% due 2048
 
600,000

 

Total notes
 
2,775,000

 
2,025,000

 
 
 
 
 
Other financing obligation
 
1,067,286

 
230,926

 
 
 
 
 
Total long-term debt, including current portion
 
4,049,786

 
2,463,426

Unamortized debt issuance costs
 
(24,242
)
 
(15,377
)
Unamortized debt premium and discount, net
 
(11,137
)
 
(5,043
)
Long-term debt due within one year
 
(15,419
)
 
(251,430
)
 
 
 
 
 
Total long-term debt
 
$
3,998,988

 
$
2,191,576

Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2018, for the next five years, are as follows (in thousands): 
2019:     Other financing obligation
 
$
15,419

2020:     Other financing obligation
 
$
17,042

2021:     Other financing obligation
 
$
18,837

2022:     Other financing obligation
 
$
20,821

2023:     Other financing obligation
 
$
23,014

No property is pledged as collateral under any of our long-term debt issues.
Restrictive Debt Covenants
At December 31, 2018, none of our debt instruments restrict the amount of distributions to our parent, provided, however, that under the credit facility described below, we are restricted from making distributions to our parent during an event of default if we have directly incurred indebtedness under the credit facility. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels and to guarantee certain indebtedness. The indenture governing our $1 billion of 7.85 percent Senior Notes due 2026 further restricts our ability to guarantee certain indebtedness.

47


Issuance and Retirement of Long-Term Debt
On March 15, 2018, we issued $400 million of 4.0 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private debt placement. We used the net proceeds to repay indebtedness, including our $250 million of 6.05 percent senior unsecured notes due 2018 upon their maturity on June 15, 2018, and for general corporate purposes, including the funding of capital expenditures. The notes were issued under an Indenture, dated as of March 15, 2018 between us and The Bank of New York Mellon Trust Company, N.A., as trustee. As part of the issuance, we entered into a registration rights agreement with the initial purchasers of the notes. Under the terms of the agreement, we were obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act within 365 days after closing and to use commercially reasonable efforts to complete the exchange offer. We filed a registration statement, which was subsequently declared effective by the SEC, and consummated the exchange offer in the third quarter of 2018.
Other Financing Obligations
Dalton Expansion Project
During the construction of our Dalton Expansion Project, we received funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. Amounts received were recorded in Advances for construction costs and 100 percent of the costs associated with construction were capitalized on our Consolidated Balance Sheet. Upon placing the project in service during the third quarter of 2017, we began leasing this co-owner's undivided interest in the lateral, including the associated pipeline capacity, and reclassified approximately $235.8 million of funding previously received from our co-owner from Advances for construction costs to Long-Term Debt on our Consolidated Balance Sheet to reflect the financing obligation payable to our co-owner over an expected term of 35 years. At December 31, 2017, the amount included in Long-Term Debt on our Consolidated Balance Sheet for financing obligation is $229.4 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet is $1.6 million. As this transaction did not meet the criteria for sale leaseback accounting due to our continued involvement, it was accounted for as a financing arrangement over the course of the capacity agreement. The obligation matures in July 2052, requires monthly interest and principal payments, and bears an interest rate of approximately 9 percent.
During 2018, we received an additional $29.8 million of funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. At December 31, 2018, the amount included in Long-Term Debt on our Consolidated Balance Sheet for this financing obligation is $258.1 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet for this financing obligation is $1.9 million.
Atlantic Sunrise Project
During the construction of our Atlantic Sunrise Project, we received funding from a co-owner for its proportionate share of construction costs related to an undivided ownership interest in certain parts of the project. Amounts received were recorded in Advances for construction costs and 100 percent of the costs associated with construction were capitalized on our Consolidated Balance Sheet. Upon placing the project into service during October 2018, we began utilizing this co-owner's undivided interest in the lateral, including the associated pipeline capacity, and reclassified $810.3 million of funding previously received from our partner from Advances for construction costs to debt to reflect the financing obligation payable to our co-owner over an expected term of 20 years. During 2018, after the project was placed into service, we received an additional $20.5 million of funding from a co-owner for its proportionate share of construction costs related to its undivided ownership interest in Atlantic Sunrise. At December 31, 2018, the amount included in Long-Term Debt on our Consolidated Balance Sheet for this financing obligation is $793.8 million, and the amount included in Long-term debt due within one year on our Consolidated Balance Sheet for this financing obligation is $13.5 million. As this transaction did not meet the criteria for sale leaseback accounting due to our continued involvement, it was accounted for as a financing arrangement over the course of the capacity agreement. The obligation matures in 2038 requires monthly interest and principal payments, and bears an interest rate of approximately 10 percent.

48


Long-Term Debt Due Within One Year
The long-term debt due within one year at December 31, 2018 is associated with the previously described other financing obligations.
The long-term debt due within one year at December 31, 2017 is associated with the $250 million of 6.05 percent notes that matured on June 15, 2018 and with the previously described other financing obligation for the Dalton Expansion Project.
Credit Facility
On July 13, 2018, we, along with Williams and Northwest (the “borrowers”), the lenders named therein, and an administrative agent entered into a Credit Agreement with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. We and Northwest are each subject to a $500 million borrowing sublimit. The facility made available under the Credit Agreement is initially available for five years from the Credit Agreement Effective Date (the “Maturity Date”). The borrowers may request an extension of the Maturity Date for an additional one-year period up to two times, to allow a Maturity Date as late as the seventh anniversary of the Credit Agreement Effective Date, subject to certain conditions. The Credit Agreement allows for same day swingline borrowings up to an aggregate amount of $200 million, subject to other utilization of the aggregate commitments under the Credit Agreement. Letter of credit commitments of $1.0 billion are, subject to the $500 million borrowing sublimit applicable to us and Northwest, available to the borrowers. At December 31, 2018 no letters of credit have been issued and loans to Williams of $160 million were outstanding under the credit facility.
Measured as of December 31, 2018, we are in compliance with our financial covenant under the credit facility.
Various covenants may limit, among other things, a borrower's and its material subsidiaries' ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, 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 the 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 swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.'s alternate base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower's senior unsecured long-term debt ratings.
Williams participates in a commercial paper program and Williams management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $4.0 billion of unsecured commercial paper notes. At December 31, 2018, Williams had no outstanding commercial paper.

49


Lease Obligations
The future minimum lease payments under our various operating leases are as follows (in thousands):

2019
 
$
9,044

2020
 
9,014

2021
 
8,865

2022
 
8,808

2023
 
8,829

Thereafter
 
65,107

Total net minimum obligations
 
$
109,667

Our lease expense was $10.8 million in 2018, $11.0 million in 2017, and $10.6 million in 2016.
5. ARO TRUST
We are entitled to collect in rates the amounts necessary to fund our ARO. We deposit monthly, into an external trust account (ARO Trust), the revenues specifically designated for ARO. The ARO Trust carries a moderate risk portfolio. The Money Market Funds held in our ARO Trust are considered investments. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with 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, the annual funding obligation is approximately $36.4 million, with deposits made monthly.
Investments within the ARO Trust at fair value were as follows (in millions):
 
 
 
December 31, 2018
 
December 31, 2017
 
 
Amortized
Cost Basis
 
Fair
Value
 
Amortized
Cost Basis
 
Fair
Value
Money Market Funds
 
$
21.7

 
$
21.7

 
$
12.6

 
$
12.6

U.S. Equity Funds
 
46.4

 
56.8

 
35.9

 
50.5

International Equity Funds
 
21.9

 
21.4

 
20.7

 
24.6

Municipal Bond Funds
 
50.1

 
49.6

 
46.8

 
46.9

Total
 
$
140.1

 
$
149.5

 
$
116.0

 
$
134.6

6. FAIR VALUE MEASUREMENTS
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of 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.
 

50


 
 
 
 
 
 
Fair Value Measurements Using
 
 
Carrying
Amount
 
Fair
Value
 
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
 
 
 
 
 
(Millions)
 
 
 
 
Assets (liabilities) at December 31, 2018:
 
 
 
 
 
 
 
 
 
 
Measured on a recurring basis:
 
 
 
 
 
 
 
 
 
 
ARO Trust investments
 
$
149.5

 
$
149.5

 
$
149.5

 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
Additional disclosures:
 
 
 
 
 
 
 
 
 
 
Long-term debt, including current portion
 
(4,014.4
)
 
(4,785.5
)
 

 
(4,785.5
)
 

 
 
 
 
 
 
 
 
 
 
 
Assets (liabilities) at December 31, 2017:
 
 
 
 
 
 
 
 
 
 
Measured on a recurring basis:
 
 
 
 
 
 
 
 
 
 
ARO Trust investments
 
$
134.6

 
$
134.6

 
$
134.6

 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
Additional disclosures:
 
 
 
 
 
 
 
 
 
 
Long-term debt
 
(2,443.0
)
 
(3,103.3
)
 

 
(3,103.3
)
 


Fair Value 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:
ARO Trust investments - We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 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 and are reported in Other Assets-Other on the accompanying Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 5 for more information regarding the ARO Trust.
Long-term debt - The disclosed fair value of our long-term debt is determined primarily 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. The fair values of the financing obligations associated with our Dalton and Atlantic Sunrise expansions, which are included within long-term debt, were determined using an income approach (See Note 4 - Debt and Financing Agreements).
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 years ended December 31, 2018 or 2017.
7. BENEFIT PLANS
Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below.
Pension and Other Postretirement Benefit Plans
Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension costs charged to us by Williams was $12.8 million, $15.6 million and $8.7 million for 2018, 2017, and 2016, respectively. Included in our pension costs are settlement charges of $2.7 million and $7.6 million for 2018

51


and 2017, respectively. These amounts reflect the portion of Williams’ settlement charge directly charged to us which was required as a result of lump-sum benefit payments made under Williams’ program to pay out certain deferred vested pension benefits, as well as lump-sum benefit payments made throughout 2018 and 2017. In addition, we were charged $2.7 million and $4.6 million for 2018 and 2017, respectively, of allocated corporate expenses also associated with the settlement charge.

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 collected or refunded through future rate adjustments. The amount of deferred pension collections recorded as a regulatory liability at December 31, 2018 and 2017 were $48.5 million and $32.5 million, respectively.
Williams provides subsidized retiree health care and life insurance benefits to certain eligible participants. Generally, participants that 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, are eligible for subsidized retiree health care benefits. We recognized other postretirement benefit income of $5.9 million, $10.9 million and $12.0 million for 2018, 2017, and 2016, 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 amount of other postretirement benefits costs deferred as a regulatory liability at December 31, 2018 and 2017 are $79.8 million and $73.9 million, respectively. These amounts are comprised of amounts being deferred for future rate treatment of $73.9 million and $65.4 million at December 31, 2018 and 2017, respectively, and amounts of $5.9 million and $8.5 million being amortized over a period of approximately 8 years per Docket No. RP12-993 at December 31, 2018 and 2017, respectively.
Defined Contribution Plan
Williams maintains a defined contribution plan for substantially all of its employees. Williams charged us compensation expense of $7.9 million, $7.7 million and $6.5 million in 2018, 2017 and 2016, respectively, for Williams’ company matching contributions to this plan.
Employee Stock-Based Compensation Plan Information
The Williams Companies, Inc. 2007 Incentive Plan, as subsequently amended and restated, (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, 2018, 2017, and 2016 was $6.3 million, $5.7 million and $4.0 million, respectively, excluding amounts allocated from WPZ and Williams.

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8. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES
Major Customers
Operating revenues received from three of our major customers in 2018, 2017 and 2016 are as follows (in millions): 
 
2018
 
2017
 
2016
Duke Energy Corporation
$
194.5

 
$
198.4

 
$
178.9

National Grid
186.1

 
177.4

 
166.3

The Southern Company, Inc.
166.2


160.0


69.6

Affiliates
We are a participant in Williams' cash management program, and we make advances to and receive advances from Williams. At December 31, 2018 and 2017, our advances to Williams totaled approximately $33.0 million and $395.2 million, respectively. These advances are represented by demand notes and are classified as Receivables - Advances to affiliate 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 Williams' excess cash at the end of each month. At December 31, 2018, the interest rate was 2.24 percent.
Included in Operating Revenues in the accompanying Consolidated Statement of Comprehensive Income for 2018, 2017 and 2016 are revenues received from affiliates of $10.1 million, $10.3 million, and $11.2 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 2018, 2017 and 2016 is purchased gas cost from affiliates of $5.4 million, $3.9 million, and $4.3 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 $395.3 million, $370.4 million, and $318.4 million during 2018, 2017 and 2016, 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. The amount billed to us during 2016 includes $7.4 million for severance and other related costs associated with a reduction in workforce primarily recognized in the first quarter.
We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $4.7 million, $3.7 million, and $4.3 million in 2018, 2017 and 2016, respectively.
We made equity distributions of $490 million, $430 million and $440 million during 2018, 2017 and 2016, respectively. In January 2019, an additional distribution of $176 million was declared and paid.
During 2018, 2017 and 2016, our parent made contributions totaling $340 million, $410 million and $502 million, respectively, to us to fund a portion of our expenditures for additions to property, plant and equipment.
During July 2017, we recorded deferred revenue and recognized a non-cash distribution to our parent of $240 million associated with funds received by WPZ related to the March 2016 WPZ agreement with the member-sponsors of Sabal Trail regarding the Hillabee Expansion and Sabal Trail projects. Although the agreement was between WPZ

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and the member-sponsors, since the agreement was, in part, related to furthering the completion of Hillabee, this deferred revenue is assigned to our results of operations over the 25-year term of the capacity agreement with Sabal Trail.
9. ASSET RETIREMENT OBLIGATIONS
These 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 2018 and 2017, our overall asset retirement obligation changed as follows (in thousands): 
 
 
2018
 
2017
Beginning balance
 
$
363,956

 
$
275,452

Accretion (1)
 
32,924

 
104,659

New obligations
 
14,162

 
28,447

Changes in estimates of existing obligations (2)
 
(8,054
)
 
(38,470
)
Property dispositions/obligations settled
 
(8,665
)
 
(6,132
)
Ending balance
 
$
394,323

 
$
363,956


(1)
The decrease in accretion for 2018 is due to the 2017 cumulative effect of accretion adjustment associated with new AROs identified in our historical land agreements of $87 million that are not a component of new obligations.
(2)
Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rate, current estimates for removal cost, discount rates, and the estimated remaining life of assets. The decrease in 2018 is primarily due to a decrease in current estimates for onshore removal costs. The decrease in 2017 is primarily due to a decrease in current estimates for offshore 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 (See Note 5).
10. REGULATORY ASSETS AND LIABILITIES
The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2018 and December 31, 2017 are as follows (in millions):
 
Regulatory Assets
 
2018
 
2017
Grossed-up deferred taxes on equity funds used during construction
 
$
39.0

 
$
37.9

Asset retirement obligations
 
171.9

 
168.7

Asset retirement costs - Eminence
 
45.5

 
49.5

Deferred taxes - asset
 
2.7

 
3.8

Deferred cash out
 
54.9

 
42.5

Deferred gas costs
 
4.0

 
6.0

Fuel cost
 
61.2

 
61.4

Other
 
6.0

 
3.7

Total Regulatory Assets
 
$
385.2

 
$
373.5



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Regulatory Liabilities
 
2018
 
2017
Negative salvage
 
$
444.5

 
$
409.7

Deferred taxes - liability
 
450.2

 
471.1

Sentinel meter station depreciation