Table of Contents



UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ☑QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SeptemberJune 30, 20172021
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
Delaware
74-1079400
(State or other jurisdiction of

incorporation or organization)
(I.R.S. Employer

Identification No.)
2800 POST OAK BOULEVARD
HOUSTON, TEXAS
Post Oak Boulevard		77056
HoustonTexas77056
(Address of principal executive offices)(Zip Code)
Registrant’s telephone number, including area code: (713) 215-2000
NO CHANGE
(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ   No  ¨
Indicate by check mark 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  þFilerþ
Smaller reporting company¨☐
Emerging growth company¨

(Do not check if a smaller reporting 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
THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS H (1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED DISCLOSURE FORMAT.


Table of Contents

TRANSCONTINTENTALTRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
Index
 
Page
Item 1. Financial Statements
Condensed Statement of Net Income —Three and Six Months Ended June 30, 2021 and 2020
4
Condensed Balance Sheet — June 30, 2021 and December 31, 2020
5
Condensed Statement of Member's Equity — Three and Six Months Ended June 30, 2021 and 2020
7
Condensed Statement of Cash Flows — Six Months Ended June 30, 2021 and 2020
8
Notes to Condensed Financial Statements
9
Page
Part I. Financial Information:
Item 1. Financial Statements
Condensed Consolidated Statement of Comprehensive Income —Three and Nine Months Ended September 30, 2017 and 2016
4
Condensed Consolidated Balance Sheet — September 30, 2017 and December 31, 2016
5
Condensed Consolidated Statement of Cash Flows — Nine Months Ended September 30, 2017 and 2016
7
Notes to Condensed Consolidated Financial Statements
8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
1614
Item 4. Controls and Procedures
1916
1916
Item 1. Legal Proceedings
1916
16
Item 6. Exhibits
2018
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,” “assumes,” “guidance,” “outlook,” “in service date”“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;

•Business strategy;

1

•Cash flow from operations or results of operations;

•Rate case filings;

•Natural gas prices, supply, and demand; and


•Demand for our services.services; and

•The impact of the coronavirus (COVID-19) pandemic.
Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

•The impact of operational and developmental hazards and unforeseen interruptions;

•Development and rate of adoption of alternative energy sources;

•The strength and financial resources of our competitors and the effects of competition;

•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 pricesprices;

•Changes in maintenance and margins;construction costs, as well as our ability to obtain sufficient construction- related inputs, including skilled labor;

•The impact of existing and future laws and regulations, the regulatory environment, environmental matters, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;

•Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social, and governance practices;

•The physical and financial risks associated with climate change;

•Our exposure to the credit risk of our customers and counterparties;

•Our ability to successfully expand our facilities and operations;

•Whether we are able to successfully identify, evaluate, and timely execute our capital projects and investment opportunities;

•Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the availability and cost of capital;

•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;
2

Whether Williams will be able to effectively manage the transition in its board of directors and management as well as successfully execute its business restructuring;
Our ability to successfully expand our facilities and operations;
Development and rate of adoption of alternative energy sources;
The impact of operational and development hazards, unforeseen interruptions, and the availability of adequate insurance coverage for such interruptions;
The impact of existing and future laws, regulations, 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;
•The risks resulting from outbreaks or other public health crises, including COVID-19;

•Changes in the current geopolitical situation;
Our exposure to the credit risks of our customers
•Changes in U.S. governmental administration and counterparties;policies;
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,incidents, and related disruptions; and

•Additional risks described in our filings with the Securities and Exchange Commission (SEC).
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also

cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020, as filed with the SEC on February 22, 2017.24, 2021.


3

PART I — FINANCIAL INFORMATION


ITEM 1.Financial Statements.


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVENET INCOME
(Thousands of Dollars)
(Unaudited)
Three Months Ended  
June 30,		Six Months Ended  
June 30,
2021202020212020
Operating Revenues:
Natural gas sales$16,003 $20,326 $30,227 $39,980 
Natural gas transportation571,245 552,290 1,153,802 1,118,296 
Natural gas storage41,357 39,055 83,859 77,429 
Other2,634 4,020 7,128 7,354 
Total operating revenues631,239 615,691 1,275,016 1,243,059 
Operating Costs and Expenses:
Cost of natural gas sales16,003 20,326 30,227 39,980 
Cost of natural gas transportation13,919 13,529 31,533 26,925 
Operation and maintenance81,912 75,556 160,382 156,245 
Administrative and general46,424 50,764 97,177 92,935 
Depreciation and amortization117,759 113,835 235,556 227,470 
Taxes — other than income taxes24,418 21,994 48,946 44,431 
Regulatory credit resulting from tax rate changes(7,688)(7,688)(15,376)(15,376)
Other expense, net3,254 1,452 4,677 4,742 
Total operating costs and expenses296,001 289,768 593,122 577,352 
Operating Income335,238 325,923 681,894 665,707 
Other (Income) and Other Expenses:
Interest expense80,260 78,749 160,435 151,858 
Allowance for equity and borrowed funds used during construction (AFUDC)(5,724)(9,294)(9,721)(20,247)
Miscellaneous other (income) expenses, net(99)505 (47)149 
Total other (income) and other expenses74,437 69,960 150,667 131,760 
Net Income$260,801 $255,963 $531,227 $533,947 
  Three months ended 
 September 30,		 Nine months ended 
 September 30,
  2017 2016 2017 2016
Operating Revenues:        
Natural gas sales $26,763
 $31,244
 $74,867
 $67,474
Natural gas transportation 389,080
 346,004
 1,116,891
 1,042,547
Natural gas storage 33,954
 34,258
 102,778
 88,315
Other 2,255
 1,343
 3,734
 3,396
Total operating revenues 452,052
 412,849
 1,298,270
 1,201,732
         
Operating Costs and Expenses:        
Cost of natural gas sales 26,763
 31,244
 74,867
 67,474
Cost of natural gas transportation 5,828
 4,689
 15,282
 15,501
Operation and maintenance 113,101
 83,916
 267,914
 225,975
Administrative and general 43,110
 40,604
 132,020
 125,997
Depreciation and amortization 82,826
 76,755
 239,368
 231,110
Taxes — other than income taxes 15,333
 14,584
 49,131
 45,154
Other expense, net 13,475
 12,894
 43,112
 41,541
Total operating costs and expenses 300,436
 264,686
 821,694
 752,752
         
Operating Income 151,616
 148,163
 476,576
 448,980
         
Other (Income) and Other Expenses:        
Interest expense 41,304
 37,318
 115,797
 113,957
Allowance for equity and borrowed funds used during construction (AFUDC) (22,334) (19,922) (70,783) (45,656)
Equity in earnings of unconsolidated affiliates (912) (1,455) (3,322) (4,447)
Miscellaneous other (income) expenses, net (774) 309
 (5,972) 655
Total other (income) and other expenses 17,284
 16,250
 35,720
 64,509
         
Net Income 134,332
 131,913
 440,856
 384,471
         
Other comprehensive income (loss):        
Equity interest in unrealized gain (loss) on interest rate hedges (includes $38 and $41 for the three months ended and $75 and $140 for the nine months ended September 30, 2017 and September 30, 2016, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses on interest rate hedges) 72
 156
 108
 (128)
         
Comprehensive Income $134,404
 $132,069
 $440,964
 $384,343


See accompanying notes.

4


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)

June 30,
2021		December 31,
2020
ASSETS
Current Assets:
Cash$0 $0 
Receivables:
Affiliates1,652 1,011 
Advances to affiliate1,102,854 642,734 
Trade213,189 223,864 
Other13,480 14,660 
Transportation and exchange gas receivables8,756 4,627 
Inventories68,995 56,297 
Regulatory assets74,773 62,861 
Other14,924 13,847 
Total current assets1,498,623 1,019,901 
Property, Plant and Equipment:
Natural gas transmission plant17,378,112 17,123,779 
Less-Accumulated depreciation and amortization5,035,585 4,802,256 
Total property, plant and equipment, net12,342,527 12,321,523 
Other Assets:
Regulatory assets250,541 281,870 
Right-of-use assets71,427 78,899 
Other268,311 252,051 
Total other assets590,279 612,820 
Total assets$14,431,429 $13,954,244 
  September 30,
2017		 December 31,
2016
ASSETS    
     
Current Assets:    
Cash $—
 $—
Receivables:    
Affiliates 326
 489
Advances to affiliate 299,059
 811,693
Trade and other 146,471
 144,315
Transportation and exchange gas receivables 944
 1,827
Inventories 47,685
 55,209
Regulatory assets 90,367
 87,059
Other 14,179
 13,305
Total current assets 599,031
 1,113,897
     
Investments, at cost plus equity in undistributed earnings 39,571
 42,403
     
Property, Plant and Equipment:    
Natural gas transmission plant 13,136,224
 11,996,454
Less-Accumulated depreciation and amortization 3,833,689
 3,687,473
Total property, plant and equipment, net 9,302,535
 8,308,981
     
Other Assets:    
Regulatory assets 269,000
 264,001
Other 132,052
 102,198
Total other assets 401,052
 366,199
     
Total assets $10,342,189
 $9,831,480


(continued)








See accompanying notes.

5

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)

June 30,
2021		December 31,
2020
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Payables:
Affiliates$47,458 $32,676 
Trade and other154,159 128,449 
Transportation and exchange gas payables3,893 1,905 
Regulatory liabilities58,139 57,086 
Accrued liabilities238,647 242,379 
Long-term debt due within one year23,677 22,640 
Total current liabilities525,973 485,135 
Long-Term Debt5,208,205 5,217,140 
Other Long-Term Liabilities:
Asset retirement obligations425,365 397,737 
Regulatory liabilities921,804 946,774 
Deferred revenue199,751 205,030 
Lease liability70,567 78,688 
Other66,088 42,921 
Total other long-term liabilities1,683,575 1,671,150 
Contingent Liabilities and Commitments (Note 3)00
Member’s Equity:
Member’s capital4,676,499 4,543,499 
Retained earnings2,337,177 2,037,320 
Total member’s equity7,013,676 6,580,819 
Total liabilities and member’s equity$14,431,429 $13,954,244 

  September 30,
2017		 December 31,
2016
LIABILITIES AND OWNER’S EQUITY    
     
Current Liabilities:    
Payables:    
Affiliates $23,483
 $29,455
Trade and other 305,949
 251,872
Transportation and exchange gas payables 3,555
 1,571
Accrued liabilities 160,087
 197,697
Long-term debt due within one year 251,320
 —
Total current liabilities 744,394
 480,595
     
Long-Term Debt 2,197,717
 2,210,754
     
Other Long-Term Liabilities: 
 
Asset retirement obligations 271,211
 248,518
Regulatory liabilities 501,201
 449,391
Advances for construction costs 261,487
 283,028
Transportation prepayments 11,115
 11,837
Deferred revenue 228,258
 —
Other 4,573
 6,088
Total other long-term liabilities 1,277,845
 998,862
     
Contingent Liabilities and Commitments (Note 2) 
 
     
Owner’s Equity: 
 
Member’s capital 3,788,499
 3,678,499
Retained earnings 2,333,616
 2,462,760
Accumulated other comprehensive income 118
 10
Total owner’s equity 6,122,233
 6,141,269
     
Total liabilities and owner’s equity $10,342,189
 $9,831,480







See accompanying notes.



6

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATEDSTATEMENT OF MEMBER’S EQUITY
(Thousands of Dollars)
(Unaudited)
Three Months Ended June 30,
20212020
Member’s Capital:
Balance at beginning of period$4,603,499 $4,428,499 
Cash contributions from parent73,000 0 
Balance at end of period4,676,499 4,428,499 
Retained Earnings:
Balance at beginning of period2,307,746 2,185,268 
Net income260,801 255,963 
Cash distributions to parent(231,370)(265,000)
Balance at end of period2,337,177 2,176,231 
Total Member’s Equity$7,013,676 $6,604,730 
Six Months Ended June 30,
20212020
Member’s Capital:
Balance at beginning of period$4,543,499 $4,428,499 
Cash contributions from parent133,000 0 
Balance at end of period4,676,499 4,428,499 
Retained Earnings:
Balance at beginning of period2,037,320 2,177,284 
Net income531,227 533,947 
Cash distributions to parent(231,370)(535,000)
Balance at end of period2,337,177 2,176,231 
Total Member’s Equity$7,013,676 $6,604,730 

See accompanying notes.
7

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
 Nine months ended September 30,Six Months Ended June 30,
 2017 201620212020
Cash flows from operating activities:    Cash flows from operating activities:
Net income $440,856
 $384,471
Net income$531,227 $533,947 
Adjustments to reconcile net income to net cash provided by (used in) operating activities:    Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization 239,368
 231,110
Depreciation and amortization235,556 227,470 
Allowance for equity funds used during construction (equity AFUDC) (53,867) (37,285)Allowance for equity funds used during construction (equity AFUDC)(7,481)(15,073)
Regulatory credit resulting from tax rate changesRegulatory credit resulting from tax rate changes(15,376)(15,376)
Changes in operating assets and liabilities:    Changes in operating assets and liabilities:
Receivables — affiliates 163
 341
Receivables — affiliates(641)(319)
— trade and other (2,156) 17,045
— trade and other11,855 38,704 
Transportation and exchange gas receivable 883
 (216)Transportation and exchange gas receivable(4,129)(829)
Inventories 7,524
 13,617
Inventories(12,698)(8,416)
Payables — affiliates (5,972) (23,340)Payables — affiliates14,782 5,520 
— trade (28,536) 6,041
 — trade8,135 282,731 
Accrued liabilities (41,137) 61,484
Accrued liabilities22,929 43,104 
Asset retirement obligations - non-current 45,629
 3,761
Asset retirement obligations - removal costs (1,708) (2,688)
Reserve for rate refundsReserve for rate refunds0 (188,842)
Asset retirement obligationsAsset retirement obligations5,661 (23,299)
Deferred revenue (2,142) —
Deferred revenue(5,279)(5,282)
Other, net (4,691) 23,451
Other, net155 2,191 
Net cash provided by operating activities 594,214
 677,792
Net cash provided by operating activities784,696 876,231 
    
Cash flows from financing activities:    Cash flows from financing activities:
Proceeds from long-term debt —
 998,250
Proceeds from long-term debt0 1,195,629 
Retirement of long-term debt —
 (200,000)
Payments on other financing obligation (241) —
Proceeds from other financing obligationsProceeds from other financing obligations1,790 5,079 
Payments on other financing obligationsPayments on other financing obligations(10,984)(9,786)
Payments for debt issuance costs (13) (8,235)Payments for debt issuance costs(32)(9,790)
Cash distributions to parent (330,000) (350,000)Cash distributions to parent(231,370)(535,000)
Cash contributions from parent 110,000
 372,000
Cash contributions from parent133,000 0 
Advances from affiliate, netAdvances from affiliate, net0 (252,549)
Net cash provided by (used in) financing activities (220,254) 812,015
Net cash provided by (used in) financing activities(107,596)393,583 
    
Cash flows from investing activities:    Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC* (1,089,917) (906,105)
Capital expenditures*Capital expenditures*(231,903)(343,234)
Contributions and advances for construction costs 252,249
 157,545
Contributions and advances for construction costs26,388 14,852 
Disposal of property, plant and equipment, net (33,281) (4,439)Disposal of property, plant and equipment, net(8,966)(18,686)
Advances to affiliate, net 512,634
 (718,279)Advances to affiliate, net(460,120)(905,827)
Return of capital from unconsolidated affiliates 2,729
 2,106
Purchase of ARO Trust investments (46,709) (61,086)Purchase of ARO Trust investments(17,925)(45,048)
Proceeds from sale of ARO Trust investments 27,520
 38,330
Proceeds from sale of ARO Trust investments15,426 28,129 
Proceeds from insurance 3,200
 2,121
Other, net (2,385) —
Net cash used in investing activities (373,960) (1,489,807)Net cash used in investing activities(677,100)(1,269,814)
    
Increase (decrease) in cash —
 —
Increase (decrease) in cash0 0 
Cash at beginning of period —
 —
Cash at beginning of period0 0 
Cash at end of period $—
 $—
Cash at end of period$0 $0 
    
* Increase to property, plant and equipment, net of equity AFUDC $(1,154,317) $(907,023)
* Increase to property, plant and equipment, exclusive of equity AFUDC* Increase to property, plant and equipment, exclusive of equity AFUDC$(235,046)$(304,167)
Changes in related accounts payable and accrued liabilities 64,400
 918
Changes in related accounts payable and accrued liabilities3,143 (39,067)
Property, plant and equipment additions, net of equity AFUDC $(1,089,917) $(906,105)
Capital expendituresCapital expenditures$(231,903)$(343,234)
See accompanying notes.

8

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. BASIS OF PRESENTATION
In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and, unless the context otherwise requires, all of our majority-owned subsidiaries)(Transco) is at times referred to in the first person as “we,” “us” or “our.”
Transco is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). In January 2017, Williams permanently waived the WPZ general partner's incentive distribution rights, converted its 2 percent general partner interest in WPZ to a non-economic interest and purchased additional WPZ common units. At September 30, 2017, Williams owns a 74 percent limited partner interest in WPZ.
General
The accompanying condensed consolidated unaudited 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 September 30, 2017 and December 31, 2016 consist of Cardinal Pipeline Company, LLC (Cardinal) with an ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with an ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $6.3 million and $6.5 million in the nine months ended September 30, 2017 and September 30, 2016, respectively. Included in the distributions are $2.7 million and $2.1 million return of capital in 2017 and 2016, respectively.
The condensed consolidated unaudited financial statements have been prepared from our books and records. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted in this Form 10-Q pursuant to Securities and Exchange Commission rules and regulations. The condensed consolidated unaudited financial statements include all normal recurring adjustments and others which, in the opinion of our management, are necessary to present fairly our interim financial statements. These condensed consolidated unaudited financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 20162020 Annual Report on Form 10-K.
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated unaudited financial statements and accompanying notes. Actual results could differ from those estimates.
Accounting Standards Issued But Not Yet Adopted
In August 2016,2. 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 Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-15 “StatementCondensed Statement of Cash Flows (Topic 230): ClassificationNet Income.
Contract Liabilities
The following table presents a reconciliation of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 provides specific guidanceour contract liabilities:
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
(Thousands)
Balance at beginning of period$212,958 $223,523 $215,596 $226,164 
Recognized in revenue(2,641)(2,641)(5,279)(5,282)
Balance at end of period$210,317 $220,882 $210,317 $220,882 

Remaining Performance Obligations
Our remaining performance obligations primarily include reservation charges on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted. ASU 2016-15 requires a retrospective transition. We do not expect ASU 2016-15 to have a material impactcontracted capacity on our consolidated financial statements.
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 assetsfirm transportation and storage contracts with customers. Amounts from 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 resultcontracts included 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. ASU 2016-13 requires varying transition methods for the different categories of amendments. We do not expect ASU 2016-13 to have a significant impact on our consolidated 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 clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease classifications, and causes lessees to recognize leases on the balance sheet as a lease liability with a corresponding right-of-use asset. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. Wetable below, which are in the process of reviewing contracts to identify leases, as well as evaluating the applicability of ASU 2016-02 to contracts involving easement/rights-of-way.
In May 2014, the FASB issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016.
We continue to evaluate the impact ASC 606 may have on our financial statements. For each revenue contract type, we are conducting a formal contract review process to evaluate the impact, if any, that ASC 606 may have. We continue to evaluate contracts with a significant financing component, which may exist in situations where the timing of the consideration we receive varies significantly from the timing of when we provide the service, as well as a certain contract with prepayments for services. We are unable to determine the potential impact upon the amount and the timing of our revenue recognition. We continue to develop and evaluate disclosures required under the new standard, with a particular focus on the scope of contracts subject to disclosure of remaining performance obligations. Additionally, we have identified possible financial systemperiodic review and internal control changes necessary for adoption. We currently anticipate utilizing a modified retrospective transition upon the adoption of ASC 606 as of January 1, 2018.
2. CONTINGENT LIABILITIES AND COMMITMENTS
Rate Matters
General rate case (Docket No. RP06-569) On August 31, 2006, we submitted toapproval by the Federal Energy Regulatory Commission (FERC) a general rate filing principally designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.
The one issue reserved for litigation or further settlement relates to our proposal to change the design of, reflect the rates for service undersuch services in our WSS-OA storage rate schedule, which was implemented subject tocurrent FERC tariffs, net of estimated reserve for refund, for the life of the related contracts; however, these rates may change based on March 1, 2007. Following a hearing,future tariffs approved by the FERC issued an opinion approvingand the amount and timing of these changes is not currently known. This table excludes the variable consideration component for commodity charges. Certain of our proposed incremental rate design, and subsequently denied requestscontracts contain evergreen provisions for rehearing of that approval. On February 21, 2014,periods beyond the U. S. Court of Appeals for the D.C. Circuit (D.C. Circuit) issued an opinion that vacated and remanded the FERC's order because the FERC did not adequately support its conclusions. On March 17, 2016, the FERC issued an order addressing the issues raised by the D.C. Circuit's opinion. In the March 17 order, the FERC reversed its prior opinion and found that Transco's incremental rate design is unjust and unreasonable. The FERC directed Transco to design its WSS-OA rates on a rolled-in basis, to file revised WSS-OA rates reflecting the findings in the order, and to refund the amounts collected in excess of those rates since March 1, 2007. On April 18, 2016, we submitted the compliance filing reflecting rolled-in rates for WSS-OA service consistent with the March 17 order, and began charging those rates beginning April 19, 2016. We also filed a request for rehearinginitial term of the March 17 order. On October 4, 2017,contract. The remaining performance obligations, as of June 30, 2021, do not consider potential future performance
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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 issued an order denying all requests for rehearingauthorization to be placed into service.
The following table presents the amount of the March 17 order, accepting our April 18, 2016 compliance filing,contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and directing usthe transaction price allocated to make refunds. Asthe remaining performance obligations under certain contracts as of SeptemberJune 30, 2017, we have accrued a liability for refunds of $19.3 million in Payables2021.
Contract LiabilitiesRemaining Performance Obligations
(Thousands)
2021 (six months)$5,287 $1,193,633 
2022 (one year)10,566 2,271,960 
2023 (one year)10,566 2,078,197 
2024 (one year)10,568 1,751,713 
2025 (one year)10,566 1,463,079 
Thereafter 00162,764 12,222,490 
Total$210,317 $20,981,072 
Accounts Receivable
Receivables from contracts with customers are included within Receivables - Trade and Receivables - Affiliates, and otherreceivables that are not related to contracts with customers are included within the balance of Receivables - Advances to affiliate and Receivables - Other in the accompanying

our Condensed Consolidated Balance Sheet. Assuming no further request for rehearing of the order is filed, we expect to issue refunds in the fourth quarter of 2017.
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.
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 are a defendant in 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 believe that it is probable that any ultimate losses incurred will be covered by our general liability insurance policy.3. CONTINGENT LIABILITIES AND COMMITMENTS
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 $6 million to $8 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. 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 SeptemberJune 30, 2017,2021, we had a balance ofhave accrued approximately $3.9$2.7 million for the expense portion of these estimated costs, $2.1$0.7 million of which is recorded in Accrued liabilities and $1.8$2.0 million of which is recorded in Other Long-Term Liabilities - Other in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2016,2020, we had a balance of approximately $4.2$2.4 million for the expense portion of these estimated costs, $2.1$0.7 million of which is recorded in Accrued liabilities and $2.1$1.7 million of which is recorded in Other Long-Term Liabilities - Other in the accompanying Condensed 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 $6 million to $8 million rangeenvironmental liabilities discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.


In March 2008,The EPA and various state regulatory agencies routinely propose and promulgate new rules, and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, review and updates to the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS)Standards, and rules for ground-level ozone. In May 2012, the EPA completed designationnew and existing source performance standards for volatile organic compounds and methane. We continuously monitor these regulatory changes and how they may impact our
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operations. Implementation of new eight-hour ozone non-attainment areas. Several ofor modified regulations may result in impacts to our facilities are located in 2008 ozone non-attainment areas. To date, no federal actions have been proposed to mandate additional emission controls at these facilities. Pursuant to recently finalized state regulatory actions associated with implementation of the 2008 ozone standard, we anticipate that some facilities may be subject to increased controls within five years. As a result,operations and increase the cost of additions to property,Property, plant, and equipment, is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet the proposed regulations.
In December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels and subsequently finalized a rule on October 1, 2015. We are monitoring the rule's implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. As a result, the cost of additions to property, plant and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations.
In February 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. In January 2012, the EPA determined pursuant to available information that no areanet in the country is violating the 2010 NO2 NAAQSCondensed Balance Sheet for both new and thus designated all areas of the country as “unclassifiable/attainment.” However, the EPA or states may require ambient air quality modelingexisting facilities in affected areas; however, due to regulatory uncertainty on a case by case basis to demonstrate compliance with the NO2 standard. Becausefinal rule content and applicability timeframes, we are unable to predict the outcome of the EPA’s or states’ assessment of NO2 compliance, we are unable toreasonably estimate the cost of additions that may be required to meetthese regulatory impacts at this regulation.time.
We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Condensed Consolidated Balance Sheet until collected through rates. At September 30, 2017, we had a balance of approximately $1.6 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $0.4 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2016, we had a balance of approximately $2.5 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $1.3 million recorded in Other Assets - Regulatory assets in the accompanying Condensed Consolidated Balance Sheet.
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.
3.4. DEBT AND FINANCING ARRANGEMENTS
Credit Facility
We, along with WPZWilliams and Northwest Pipeline LLC (Northwest), are party to a credit agreement with aggregate commitments available of $3.5$4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. Total letterWe and Northwest are each subject to a $500 million borrowing sublimit. Letter of credit capacity availablecommitments of $1.0 billion are subject to WPZ under this credit facility is $1.125 billion. We

are able to borrow up tothe $500 million under this credit facilityborrowing sublimit applicable to the extent not otherwise utilized by the other co-borrowers.us and Northwest. At SeptemberJune 30, 2017, no2021, 0 letters of credit have been issued, and no0 loans were outstanding under the credit facility.
WPZWilliams participates in a commercial paper program and WPZWilliams’ 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 $3$4.0 billion of unsecured commercial paper notes. At SeptemberJune 30, 2017, no2021, Williams had 0 outstanding commercial paper was outstanding under the commercial paper program.paper.
Other Financing ObligationObligations
During the construction of our Dalton Expansion Project
At June 30, 2021, the amount included in Long-Term Debt on our Condensed Balance Sheet for this financing obligation is $253.2 million, and the amount included in Long-term debt due within one year on our Condensed Balance Sheet for this financing obligation is $2.4 million.
Atlantic Sunrise Project
During the first six months of 2021, we received an additional $1.8 million of funding from a partnerco-owner for its proportionate share of construction costs related to its undivided ownership interest in certain parts of the Dalton lateral. Amounts received were recordedproject. This additional funding is reflected in Advances for construction costsLong-Term Debt on our Condensed Consolidated Balance Sheet. Upon placingAt June 30, 2021, the projectamount included in service during the third quarter of 2017, we began leasing this partner's undivided interest in the lateral, including the associated pipeline capacity, and reclassified approximately $235.8 million of funding previously received from our partner from Advances for construction costs to Long-Term Debt on our Condensed Consolidated Balance Sheet to reflect thefor this financing obligation payable to our partner over an expected term of 35 years. As this transaction did not meetis $818.0 million, and 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 maturesamount included in July 2052, requires monthly interest and principal payments, and bears an interest rate of approximately 10 percent.
Long-Term Debt Due Within One Year
The long-termLong-term debt due within one year at September 30, 2017on our Condensed Balance Sheet for this financing obligation is associated with the $250 million of 6.05 percent notes maturing on June 15, 2018 and $1.5 million associated with the previously described other financing obligation.$21.3 million.
4.5. ARO TRUST
Available-for-Sale Investments
We are entitled to collect in rates the amounts necessary to fund our asset retirement obligations (ARO). We deposit monthly, into an external trust account (ARO Trust), the revenues specifically designated for ARO. The
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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 the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.
Effective March 1, 2013,2020, the annual funding obligation is approximately $36.4$16.0 million, with deposits made monthly.
Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions):
June 30, 2021December 31, 2020
Amortized
Cost Basis		Fair
Value		Amortized
Cost Basis		Fair
Value
Money Market Funds$9.4 $9.4 $5.8 $5.8 
U.S. Equity Funds52.7 112.0 59.9 108.0 
International Equity Funds31.7 44.5 34.2 43.7 
Municipal Bond Funds87.5 90.6 74.9 78.0 
Total$181.3 $256.5 $174.8 $235.5 

 September 30, 2017 December 31, 2016
 
Amortized
Cost Basis
 
Fair
Value
 
Amortized
Cost Basis
 
Fair
Value
Cash and Money Market Funds$8.5
 $8.5
 $5.0
 $5.0
U.S. Equity Funds35.9
 47.7
 29.4
 36.5
International Equity Funds20.7
 23.7
 19.2
 18.6
Municipal Bond Funds46.8
 47.1
 36.7
 36.3
Total$111.9
 $127.0
 $90.3
 $96.4


5.6. 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 cash, short-term financial assets (advances to affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
 
Fair Value Measurements Using
     Fair Value Measurements UsingCarrying
Amount		Fair ValueQuoted
Prices In
Active
Markets for
Identical
Assets
(Level  1)		Significant
Other
Observable
Inputs
(Level 2)		Significant
Unobservable
Inputs
(Level 3)
 
Carrying
Amount
 Fair Value 
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level  1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
(Millions)
 (Millions)
Assets (liabilities) at September 30, 2017:          
Assets (liabilities) at June 30, 2021:Assets (liabilities) at June 30, 2021:
Measured on a recurring basis:          Measured on a recurring basis:
ARO Trust investments $127.0
 $127.0
 $127.0
 $—
 $—
ARO Trust investments$256.5 $256.5 $256.5 $0 $0 
          
Additional disclosures:          Additional disclosures:
Long-term debt, including current portion (2,449.0) (3,051.1) —
 (3,051.1) —
Long-term debt, including current portion(5,231.9)(6,764.2)0 (6,764.2)0 
          
Assets (liabilities) at December 31, 2016:          
Assets (liabilities) at December 31, 2020:Assets (liabilities) at December 31, 2020:
Measured on a recurring basis:          Measured on a recurring basis:
ARO Trust investments $96.4
 $96.4
 $96.4
 $—
 $—
ARO Trust investments$235.5 $235.5 $235.5 $0 $0 
          
Additional disclosures:          Additional disclosures:
Long-term debt (2,210.8) (2,507.5) —
 (2,507.5) —
Long-term debt, including current portionLong-term debt, including current portion(5,239.8)(6,949.0)0 (6,949.0)0 
Fair Value of Methods
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
ARO Trust investments — We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993RP18-1126 rate case settlement, into the ARO Trust, which is specifically designated to fund future asset retirement
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obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market are classified as available-for-sale and are reported in Other Assets-Other in the Condensed Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See(See Note 4 5. ARO Trust for more information regarding the ARO Trust.)
Long-term debt, including current portion — 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 value of the financing obligationobligations associated with our Dalton lateral,and Atlantic Sunrise expansions, which isare included within long-term debt, waswere determined using an income approach (See Note 3 - 4. Debt and Financing Arrangements).
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 nine months ended September 30, 2017 or 2016.
6.7. TRANSACTIONS WITH AFFILIATES
We are a participant in WPZ’sWilliams’ cash management program, and we receive advances from and make advances to Williams. At June 30, 2021 and receive advances from WPZ. At September 30, 2017 and December 31, 2016,2020, our advances to WPZWilliams totaled approximately $299.1$1,102.9 million and $811.7$642.7 million,, respectively. These advances are represented by demand notes and are classified as Receivables - Advances to affiliatein the accompanying Condensed Consolidated Balance Sheet. Advances are stated at the historical

carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’sWilliams’ excess cash at the end of each month. At SeptemberJune 30, 2017,2021, the interest rate was 0.910.01 percent.
Included in Operating Revenues in the accompanying Condensed Consolidated Statement of ComprehensiveNet Income are revenues received from affiliates of $2.5$2.1 million and $8.9 million for the three and nine months ended September 30, 2017, respectively, and $4.8 million and $8.9$4.7 million for the three and ninesix months ended SeptemberJune 30, 2016,2021, respectively, and $2.6 million and $5.2 million for the three and six months ended June 30, 2020, 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 Condensed Consolidated Statement of ComprehensiveNet Income are costcosts of gas purchased from affiliates of $1.0$0.7 million and $2.9 million for the three and nine months ended September 30, 2017, respectively, and $1.8 million and $3.3$4.1 million for the three and ninesix months ended SeptemberJune 30, 2016,2021, respectively, and $0.5 million and $3.0 million for the three and six months ended June 30, 2020, respectively. All gas purchases are made at market or contract prices.
We have no0 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 $91.4$94.5 million and $261.1 million in the three and nine months ended September 30, 2017, respectively and $78.4 million and $234.7$189.2 million in the three and ninesix months ended SeptemberJune 30, 2016,2021, respectively, and $91.6 million and $178.5 million in the three and six months ended June 30, 2020, respectively, for these services. Such expenses are primarily included in Operation and maintenance and Administrative and general expenses in the accompanying Condensed Consolidated Statement of ComprehensiveNet Income. The amount billed to us for the nine months ended September 30, 2016, includes $6.3 million recognized in the first quarter for severance and other related costs associated with a reduction in workforce.
We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $0.9$1.8 million and $2.7$3.5 million for the three and ninesix months ended SeptemberJune 30, 2017,2021, respectively, and $1.0$1.2 million and $3.4$2.2 million for the three and ninesix months ended SeptemberJune 30, 2016,2020, respectively.
We made equity distributions totaling $330.0$231.4 million and $350.0$535.0 million during the ninesix months ended SeptemberJune 30, 20172021 and 2016,2020, respectively. During October 2017,July 2021, we made an additionala distribution of $100.0$56.6 million. Our parent made contributions to us totaling $110.0$133.0 million and $372.0 million in during the ninesix months ended SeptemberJune 30, 2017 and 2016, respectively,2021 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 distributionto2021, our parent of $240made an additional $139.0 million associated with funds received by WPZ relatedcontribution 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 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.
7. OTHER
For the nine months ended September 30, 2017 and 2016, we capitalized $0.2 million and $1.4 million, respectively, of project feasibility costs, which had been expensed in prior periods in Other expense, net, upon determining that the project was probable of development.
The Advances for construction costs on the accompanying Condensed Consolidated Balance Sheet are associated with advances received from third parties related to construction costs on the Atlantic Sunrise and Dalton projects. This balance increases as we receive additional advances. After construction of the respective projects are completed, the related liabilities will be reclassified to Long-Term Debt and reduced by payments we make to the third parties

under terms of the applicable lease agreements. In the third quarter 2017, the advances received from a third party related to construction costs on the Dalton lateral was reclassified to Long-Term Debt on our Condensed Consolidated Balance Sheet.

us.
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ITEM 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
The following discussion should be read in conjunction with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis contained in Items 7 and 8 of our 20162020 Annual Report on Form 10-K and with the Condensed Consolidated Financial Statements and Notes contained in this Form 10-Q.
RESULTS OF OPERATIONS
Operating Income and Net Income
Operating Income for the ninesix months ended SeptemberJune 30, 20172021 was $476.6$681.9 million compared to $449.0$665.7 million for the nine months ended September 30, 2016.same period in 2020. The increase in Operating Income of $27.6$16.2 million (6.1(2.4 percent) was primarily due to higher Natural gas transportation and Natural gas storage revenues in the first ninesix months of 20172021 compared to the same period in 2016, partly2020, partially offset by an increaseunfavorable change in Operating Costs and Expenses, as discussed below. Net Income for the ninesix months ended SeptemberJune 30, 20172021 was $440.9$531.2 million compared to $384.5$533.9 million for the nine months ended September 30, 2016.same period in 2020. The increasedecrease in Net Income of $56.4$2.7 million (14.7(0.5 percent) was mostly attributable to thean increase in Operating Income and a favorable change in net expenses in Other (Income) and Other Expenses, as discussed below.
Operating Revenues
Natural gas sales increased $7.4decreased $9.8 million (11.0(24.4 percent) for the ninesix months ended SeptemberJune 30, 20172021 compared to the same period in 2016.2020. The increasedecrease was primarily due to system management gaslower cash out sales. System management gasCash out sales are offset in our cost of natural gas soldsales and therefore have no impact on our operating income or results of operations.net income.
Natural gas transportation for the ninesix months ended SeptemberJune 30, 20172021 increased $74.4$35.5 million (7.1(3.2 percent) over the same period in 2016.2020. The increase was primarily attributable to:
•$34.3 million from our Southeastern Trail project placed in service in November 2020;
•$10.6 million from our Leidy South project partially placed in service in November 2020;
•$7.9 million from our Hillabee 2 project placed in service in May 2020;
•$4.6 million higher electric power costs. Electric power costs are recovered from our customers through transportation rates resulting in no net impact on our operating income or results of operations; and
•$1.9 million increase in short-term firm transportation.
•Partially offset by a decrease of $12.3 million primarily resulting from the implementation of lower rates for certain services coincident with the effective date of our last rate case settlement;
•$6.0 million lower revenue due to one less billable day; and
•$5.5 million lower revenues on long haul firm transportation.
Natural gas storage increased $6.4 million (8.3 percent) for the six months ended June 30, 2021 compared to the same period in 2020. The increase was primarily due to higher transportation reservationan increase in rates effective in the second quarter of 2020.
Operating Costs and Expenses
Excluding the Cost of natural gas sales, which is directly offset in revenues, related to new incremental projects of $88.4our operating costs and expenses increased $25.5 million (primarily due to $38.3 million from our Gulf Trace project placed in service in February 2017, $28.0 million from our Dalton project placed in partial service in April 2017, and fully in service in August 2017, $11.2 million from our Hillabee project Phase I placed in partial service in June 2017 and fully in service in July 2017 and $8.3 million from our Rock Springs project placed in service in August 2016), partially offset by $6.7 million lower commodity revenues, $3.6 million due to one less billable day in 2017 compared to 2016, and $3.5 million lower firm transportation backhaul revenues.
Natural gas storage increased $14.5 million (16.4(4.7 percent) for the ninesix months ended SeptemberJune 30, 20172021 compared to the same period in 2016. The increase was primarily due to the absence of an accrual for Washington Storage Service potential refunds recorded in 2016.
Operating Costs and Expenses
Excluding the Cost of natural gas sales, which is directly offset in revenues, of $74.9 million for the nine months ended September 30, 2017 and $67.5 million for the comparable period in 2016, our operating costs and expenses for the nine months ended September 30, 2017 increased approximately $61.5 million (9.0 percent) from the comparable period in 2016.2020. This increase was primarily attributable to:
A $41.9 million (18.5 percent) increase in Operation and maintenance costs primarily due to $32.9 million higher costs for pipeline integrity, general maintenance and other testing on our pipeline and $4.0 million higher employee labor and related benefit costs;
An $8.3•$8.1 million (3.6 percent) increase in Depreciation and amortization costs primarily due to $12.2 million higher expense due toresulting from additional assets placed into service after third quarter 2016, partly offset by $4.3service.
•$4.6 million lower expense due to ARO-related depreciation;
A $6.0 million (4.8(17.1 percent) increase in Administrative and general costsCost of natural gas transportation primarily due to higher allocated corporate expenses; and
electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net income impact on our operating income or results of operations;
A $3.9•$4.5 million (8.6(10.2 percent) increase in Taxes - other than income taxes primarily due to higher ad valorem taxesan increase in estimated property taxes;
•$4.2 million (4.6 percent) unfavorable change in Administrative and general costs primarily due to an increase in employee labor and benefit costs; and
14

•$4.1 million (2.6 percent) unfavorable change in Operation and maintenance costs primarily resulting from $3.1 million increase in corporate allocations and $1.1 million unfavorable change in capitalization of internal labor as a result of additional assets placed into service.
fewer ongoing expansion projects.
Other (Income) and Other Expenses
Other (income) and other expenses for the ninesix months ended SeptemberJune 30, 20172021 had a favorablean unfavorable change of $28.8$18.9 million (44.7(14.3 percent) overcompared to the same period in 2016 mostly due2020. This is attributable to an increaseunfavorable change of $10.5 million inAllowance for equity and borrowed funds used during construction (AFUDC) associated withas a result of a decrease in capital expendituresspending and an increase of $8.6 million in interest expense primarily due to interest incurred on projects.new debt issued May 2020.

Recent Developments
COVID-19
The outbreak of COVID-19 has severely impacted global economic activity and caused significant volatility and negative pressure in financial markets. We continue to monitor the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees and communities, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. Our financial condition, results of operations, and liquidity have not been materially impacted by direct effects of COVID-19.

Pipeline Expansion Projects
Gulf TraceLeidy South
The Gulf Trace ExpansionLeidy South Project involves an expansion of our existing natural gas transmission system togetherand an extension of our system through a capacity lease with greenfield facilitiesNational Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation capacity from Station 65Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in St. Helena Parish, Louisiana westward to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana.Lancaster County, Pennsylvania. In July 2020, we received approval from the FERC for the project. We placed 125 Mdth/d of capacity under the project into service on February 1, 2017, and it increased capacity by 1,200 Mdth/d.
Hillabee
The Hillabee Expansion Project involves an expansionin the fourth quarter 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 will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We placed a portion of Phase I into service on June 14, 2017,2020, and we placedplan to place the remainder of Phase ITransco's facilities under the project into service on July 11, 2017. Phase I increased capacity by 818 Mdth/d. The in-service date of Phase II is planned foras early as the secondfourth quarter of 2020. Together, the first two phases of the2021. The project areis expected to increase capacity by 1,025582 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 was, in part, related to furthering the completion of the project, this deferred revenue is assigned to our results of operations over the term of the capacity agreement with Sabal Trail.
In August 2017, the Court of Appeals for the District of Columbia Circuit granted an appeal of the FERC certificate order for the Southeast Market Pipelines projects (which includes a group of related projects, including the Hillabee Expansion Project) filed by certain non-governmental organizations. In doing so, the court (i) remanded the matter to the FERC for preparation of an Environmental Impact Statement that conforms with the court's opinion regarding quantifying certain greenhouse gas emissions, and (ii) vacated the FERC's certificate order for the projects, which would be effective following the court's mandate (by court order, the mandate will not issue until after disposition of all petitions for rehearing). We, along with other intervenors, and the FERC have filed petitions for rehearing with the court to overturn the remedy that would involve vacating the FERC certificate order. If the court's mandate is issued prior to the FERC re-issuing certificate authority for the projects, we believe that the FERC will take the necessary steps (which may include issuing temporary certificate authority) to avoid any lapse in federal authorization for the projects.
Garden StateRegional Energy Access
The Garden StateRegional Energy Access Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from our Station 210 Pooling Pointreceipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, to a new interconnection onand Maryland. We filed our Trenton Woodbury Lateral in Burlington County, New Jersey. The project will be constructed in phases. The FERC certificate application for the project and the other regulatory approvals necessary to commence construction of the project have been received. We placed the initial phase of the project into service on September 9, 2017 and plan to place the remaining portion of the project into service during the second quarter of 2018. The project is expected to increase capacity by 180 Mdth/d.
Dalton
The Dalton Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from our Station 210 Pooling Point in New Jersey to markets in northwest Georgia. On April 1, 2017, we began providing firm transportation service through the mainline portion of the project (from the Station 210 Pooling Point to the interconnection with Gulf South at Holmesville in Mississippi) on an interim basis, and on August 1, 2017, we placed the full project into service. The project increased capacity by 448 Mdth/d.
Atlantic Sunrise
The Atlantic Sunrise Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along our mainline as far south as our Station 85 Pooling Point in Choctaw County, Alabama. In February 2017, we received approval from the FERC for the project. We placed a portion of the mainline project facilities into service on September 1, 2017, which increased capacity by 400 Mdth/d. We plan to place the full project into service during mid-2018, assuming timely receipt of the remaining regulatory approvals. The full project is expected to increase capacity by 1,700 Mdth/d.

Virginia Southside II
The Virginia Southside II Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from our Station 210 Pooling Point in New Jersey and our Station 165 Pooling Point in Virginia to a proposed delivery point on a new lateral off of our Brunswick Lateral in Virginia. The FERC certificate for the project and the other regulatory approvals necessary to commence construction of the project have been received.March 26, 2021. We plan to place the project into service duringas early as the fourth quarter of 2017, and it is expected to increase capacity by 250 Mdth/d.
New York Bay Expansion
The New York Bay Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in New York. We placed the project into service on October 6, 2017, and it increased capacity by 115 Mdth/d.
Gulf Connector
The Gulf Connector Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. We filed an application with the FERC in August 2016 for approval of the project. The project will be constructed in two phases, and we plan to place both phases into service during the first half of 2019,2023, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475829 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. We filed an application with the FERC in March 2017 for approval of the project. We plan to place the project into service in late 2019 or during the first half of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.
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. We filed an application with the FERC in August 2017 for approval of 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. We expect to file an application with the FERC in the fourth quarter of 2017 for approval of 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.


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ITEM 4.Controls and Procedures
Our management, including our Senior Vice President and our Vice President Controller and Chief Accounting Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act)Act of 1934, as amended (Disclosure Controls)) or our internal control over financial reporting (Internal Controls)will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President and our Vice President Controller and Chief Accounting Officer. Based upon that evaluation, our Senior Vice President and our Vice President Controller and Chief Accounting Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes during the thirdsecond quarter of 20172021 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.


PART II — OTHER INFORMATION.


ITEM 1.Legal Proceedings
Environmental
On May 5, 2017,While it is not possible for us to predict the final outcome of any pending legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment, we entered intodo not anticipate a Consent Order with the Georgia Departmentmaterial effect on our financial position if we were to receive an unfavorable outcome in any one or more of Natural Resources, Environmental Protection Division (GEPD) pertaining to alleged violations of the Georgia Water Quality Control Act and associated rules arising fromsuch proceedings. Our threshold for disclosing material environmental legal proceedings involving a permit issued by GEPD for construction of the Dalton Project. Pursuant to the Consent Order, we paid a fine of $168,750 and agreed to perform a Corrective Action Order to remedy the alleged violations.governmental authority where potential monetary sanctions are involved is $1 million.
Other
The additional information called for by this item is provided in Note 2 of3. Contingent Liabilities and Commitments, included in the Notes to Condensed Consolidated Financial Statements included under Part I,1, Item 1. Financial Statements of this report,Form 10-Q, which information is incorporated by reference into this item.



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ITEM 1A.Risk Factors

    Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020 includes certain risk factors that could materially affect our business, financial condition, or future results. Those Risk Factors have not materially changed.  








17

ITEM 6.Exhibits
The following instruments are included as exhibits to this report.
 
Exhibit
Number		Description
Exhibit
Number
2		Description
2
Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).
3.1
Certificate of Formation dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).
3.2
Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our quarterly report on Form 10-Q (File No. 001-07584) and incorporated herein by reference).
31.1*
Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**
Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH*XBRL Taxonomy Extension Schema.
101.CAL*XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*XBRL Taxonomy Extension Definition Linkbase.
101.LAB*XBRL Taxonomy Extension Label Linkbase.
101.PRE*XBRL Taxonomy Extension Presentation Linkbase.
*Filed herewith.
**104*Furnished herewith.Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101).

*Filed herewith.
**Furnished herewith.

 



18


SIGNATURE
Pursuant to the requirements of the Securities Exchange Act 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
(Registrant)
Dated:August 2, 2021
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
(Registrant)
By:		/s/ Billeigh W. Mark
Billeigh W. Mark
Dated:November 2, 2017By:/s/ Ted T. TimmermansController
Ted T. Timmermans
Vice President, Controller and Chief Accounting Officer
(Principal Accounting Officer)