Table of Contents

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
(Mark One)
þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017March 31, 2019
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)
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  þ
 
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

TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC
Index
 
 Page
 
 
  
  
  
  
  
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“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;
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 and margins;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;
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;opportunities;
Our ability to successfully expand our facilities and operations;
Development and rate of adoption of alternative energy sources;
TheAvailability of adequate insurance coverage and the impact of operational and development hazards unforeseen interruptions, and the availability of adequate insurance coverage for suchunforeseen interruptions;
The impact of existing and future laws and 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;costs, as well as our ability to obtain sufficient construction related inputs including skilled labor;
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,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 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 filed with the SEC on February 22, 2017.21, 2019.

PART I — FINANCIAL INFORMATION

ITEM 1.Financial Statements.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)
(Unaudited)
 Three months ended 
 September 30,
 Nine months ended 
 September 30,
 Three months ended 
 March 31,
 2017 2016 2017 2016 2019 2018
Operating Revenues:            
Natural gas sales $26,763
 $31,244
 $74,867
 $67,474
 $24,086
 $25,251
Natural gas transportation 389,080
 346,004
 1,116,891
 1,042,547
 534,160
 426,579
Natural gas storage 33,954
 34,258
 102,778
 88,315
 36,085
 34,767
Other 2,255
 1,343
 3,734
 3,396
 2,762
 2,639
Total operating revenues 452,052
 412,849
 1,298,270
 1,201,732
 597,093
 489,236
            
Operating Costs and Expenses:            
Cost of natural gas sales 26,763
 31,244
 74,867
 67,474
 24,086
 25,251
Cost of natural gas transportation 5,828
 4,689
 15,282
 15,501
 14,635
 13,074
Operation and maintenance 113,101
 83,916
 267,914
 225,975
 83,448
 87,016
Administrative and general 43,110
 40,604
 132,020
 125,997
 48,151
 46,381
Depreciation and amortization 82,826
 76,755
 239,368
 231,110
 104,623
 83,224
Taxes — other than income taxes 15,333
 14,584
 49,131
 45,154
 20,277
 18,438
Regulatory credit resulting from Tax Reform (1,749) 
Other expense, net 13,475
 12,894
 43,112
 41,541
 13,349
 17,841
Total operating costs and expenses 300,436
 264,686
 821,694
 752,752
 306,820
 291,225
            
Operating Income 151,616
 148,163
 476,576
 448,980
 290,273
 198,011
            
Other (Income) and Other Expenses:            
Interest expense 41,304
 37,318
 115,797
 113,957
 71,091
 45,074
Allowance for equity and borrowed funds used during construction (AFUDC) (22,334) (19,922) (70,783) (45,656) (8,714) (26,608)
Equity in earnings of unconsolidated affiliates (912) (1,455) (3,322) (4,447)
Equity in (earnings) losses of unconsolidated affiliates (771) 1,590
Miscellaneous other (income) expenses, net (774) 309
 (5,972) 655
 (1,035) (1,961)
Total other (income) and other expenses 17,284
 16,250
 35,720
 64,509
 60,571
 18,095
            
Net Income 134,332
 131,913
 440,856
 384,471
 229,702
 179,916
            
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)
Equity interest in unrealized gain (loss) on interest rate hedges (includes $(78) for 2019 and $6 for 2018, of accumulated other comprehensive income reclassification for equity interest in realized losses (gains) on interest rate hedges) (230) 405
            
Comprehensive Income $134,404
 $132,069
 $440,964
 $384,343
 $229,472
 $180,321

See accompanying notes.


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

 September 30,
2017
 December 31,
2016
 March 31,
2019
 December 31,
2018
ASSETS        
        
Current Assets:        
Cash $
 $
 $
 $
Receivables:        
Affiliates 326
 489
 399
 1,018
Advances to affiliate 299,059
 811,693
 
 33,034
Trade and other 146,471
 144,315
 234,245
 201,198
Transportation and exchange gas receivables 944
 1,827
 6,339
 4,515
Inventories 47,685
 55,209
 67,736
 63,205
Regulatory assets 90,367
 87,059
 103,903
 95,770
Other 14,179
 13,305
 7,474
 12,574
Total current assets 599,031
 1,113,897
 420,096
 411,314
        
Investments, at cost plus equity in undistributed earnings 39,571
 42,403
 25,815
 26,520
        
Property, Plant and Equipment:        
Natural gas transmission plant 13,136,224
 11,996,454
 16,073,782
 15,908,878
Less-Accumulated depreciation and amortization 3,833,689
 3,687,473
 4,240,363
 4,147,729
Total property, plant and equipment, net 9,302,535
 8,308,981
 11,833,419
 11,761,149
        
Other Assets:        
Regulatory assets 269,000
 264,001
 273,733
 289,479
Right-of-use assets 89,824
 
Other 132,052
 102,198
 187,070
 167,490
Total other assets 401,052
 366,199
 550,627
 456,969
        
Total assets $10,342,189
 $9,831,480
 $12,829,957
 $12,655,952

(continued)




See accompanying notes.

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

 September 30,
2017
 December 31,
2016
 March 31,
2019
 December 31,
2018
LIABILITIES AND OWNER’S EQUITY    
LIABILITIES AND MEMBER’S EQUITY    
        
Current Liabilities:        
Payables:        
Affiliates $23,483
 $29,455
 $46,485
 $50,727
Advances from affiliates86,580
86,580
 
Trade and other 305,949
 251,872
 165,998
 226,911
Transportation and exchange gas payables 3,555
 1,571
 3,480
 5,973
Regulatory liabilities 44,226
 5,097
Accrued liabilities 160,087
 197,697
 208,382
 218,384
Long-term debt due within one year 251,320
 
 15,810
 15,419
Total current liabilities 744,394
 480,595
 570,961
 522,511
        
Long-Term Debt 2,197,717
 2,210,754
 4,003,258
 3,998,988
        
Other Long-Term Liabilities: 
 
 
 
Asset retirement obligations 271,211
 248,518
 366,945
 348,609
Regulatory liabilities 501,201
 449,391
 991,779
 1,026,892
Advances for construction costs 261,487
 283,028
Transportation prepayments 11,115
 11,837
Deferred revenue 228,258
 
 223,526
 226,164
Lease liability 85,759
 
Other 4,573
 6,088
 5,657
 4,188
Total other long-term liabilities 1,277,845
 998,862
 1,673,666
 1,605,853
        
Contingent Liabilities and Commitments (Note 2) 
 
Contingent Liabilities and Commitments (Note 4) 
 
        
Owner’s Equity: 
 
Member’s Equity: 
 
Member’s capital 3,788,499
 3,678,499
 4,428,499
 4,428,499
Retained earnings 2,333,616
 2,462,760
 2,153,269
 2,099,567
Accumulated other comprehensive income 118
 10
 304
 534
Total owner’s equity 6,122,233
 6,141,269
Total member’s equity 6,582,072
 6,528,600
        
Total liabilities and owner’s equity $10,342,189
 $9,831,480
Total liabilities and member’s equity $12,829,957
 $12,655,952




See accompanying notes.


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED STATEMENT OF MEMBER’S EQUITY
(Thousands of Dollars)
(Unaudited)
  Three months ended March 31,
  2019 2018
Member's Capital:    
Balance at beginning of period $4,428,499
 $4,088,499
Cash contributions from parent 
 340,000
Balance at end of period 4,428,499
 4,428,499
Retained Earnings:    
Balance at beginning of period 2,099,567
 1,848,488
Net income 229,702
 179,916
Cash distributions to parent (176,000) (55,000)
Balance at end of period 2,153,269
 1,973,404
Accumulated Other Comprehensive Income:    
Balance at beginning of period 534
 337
Equity interest in unrealized gain (loss) on interest rate hedge (230) 405
Balance at end of period 304
 742
     
Total Member's Equity $6,582,072
 $6,402,645
























See accompanying notes.


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
 Nine months ended September 30, Three months ended March 31,
 2017 2016 2019 2018
Cash flows from operating activities:        
Net income $440,856
 $384,471
 $229,702
 $179,916
Adjustments to reconcile net income to net cash provided by (used in) operating activities:        
Depreciation and amortization 239,368
 231,110
 104,623
 83,224
Allowance for equity funds used during construction (equity AFUDC) (53,867) (37,285) (6,510) (19,782)
Regulatory credit resulting from Tax Reform (1,749) 
Equity in (earnings) losses of unconsolidated affiliates (771) 1,590
Distributions from unconsolidated affiliates 1,248
 429
Changes in operating assets and liabilities:        
Receivables — affiliates 163
 341
 619
 598
— trade and other (2,156) 17,045
 (33,047) 8,612
Transportation and exchange gas receivable 883
 (216) (1,824) 275
Inventories 7,524
 13,617
 (4,531) (37,886)
Payables — affiliates (5,972) (23,340) (4,242) (29,496)
— trade (28,536) 6,041
 (45,546) (52,553)
Accrued liabilities (41,137) 61,484
 (13,105) (11,473)
Asset retirement obligations - non-current 45,629
 3,761
 18,577
 17,201
Asset retirement obligations - removal costs (1,708) (2,688)
Deferred revenue (2,142) 
 (2,638) (2,638)
Other, net (4,691) 23,451
 3,419
 (6,296)
Net cash provided by operating activities 594,214
 677,792
 244,225
 131,721
        
Cash flows from financing activities:        
Proceeds from long-term debt 
 998,250
 
 993,440
Retirement of long-term debt 
 (200,000)
Payments on other financing obligation (241) 
Proceeds from other financing obligations 7,914
 18,804
Payments on other financing obligations (3,680) (375)
Payments for debt issuance costs (13) (8,235) 
 (9,025)
Cash distributions to parent (330,000) (350,000) (176,000) (55,000)
Cash contributions from parent 110,000
 372,000
 
 340,000
Advances from affiliate, net 86,580
 
Net cash provided by (used in) financing activities (220,254) 812,015
 (85,186) 1,287,844
        
Cash flows from investing activities:        
Property, plant and equipment additions, net of equity AFUDC* (1,089,917) (906,105) (184,556) (737,004)
Contributions and advances for construction costs 252,249
 157,545
 10,057
 188,543
Disposal of property, plant and equipment, net (33,281) (4,439) (5,477) (5,241)
Advances to affiliate, net 512,634
 (718,279) 33,034
 (854,125)
Return of capital from unconsolidated affiliates 2,729
 2,106
Purchase of ARO Trust investments (46,709) (61,086) (19,518) (15,530)
Proceeds from sale of ARO Trust investments 27,520
 38,330
 9,767
 3,792
Proceeds from insurance 3,200
 2,121
Other, net (2,385) 
 (2,346) 
Net cash used in investing activities (373,960) (1,489,807) (159,039) (1,419,565)
        
Increase (decrease) in cash 
 
 
 
Cash at beginning of period 
 
 
 
Cash at end of period $
 $
 $
 $
        
* Increase to property, plant and equipment, net of equity AFUDC $(1,154,317) $(907,023) $(161,741) $(721,921)
Changes in related accounts payable and accrued liabilities 64,400
 918
 (22,815) (15,083)
Property, plant and equipment additions, net of equity AFUDC $(1,089,917) $(906,105) $(184,556) $(737,004)
See accompanying notes.

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) 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 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, 2017March 31, 2019 and December 31, 20162018 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$1.2 million and $6.5$0.4 million in the ninethree months ended September 30, 2017March 31, 2019 and September 30, 2016March 31, 2018, 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 20162018 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.
A reclassification within operating activities in the Condensed Consolidated Statement of Cash Flows between Accrued liabilities and Other, net of $1.9 million for the three months ended March 31, 2018, has been made to conform to the 2019 presentation.
Income Taxes
We generally are not a taxable entity for federal or state and local income tax purposes. The tax on net income is generally borne by our parent, 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.
Revenue Subject to Refund
Federal Energy Regulatory Commission (FERC) regulations promulgate policies and procedures which govern a process to establish the rates that we are permitted to charge customers for natural gas sales and services, including the transportation and storage of natural gas. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related taxes, and (3) volume throughput assumptions.

As a result of the ratemaking process, certain revenues collected by us may be subject to refund 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 estimated total exposure, as well as collection and other risks. Depending on the results of these proceedings, the actual amounts allowed to be collected from customers could differ from management's estimate. In addition, as a result of rate orders, tariff provisions or regulations, we are required to refund or credit certain revenues to our customers. At March 31, 2019, we have provided a reserve for rate refunds related to Docket No. RP18-1126 which we believe is adequate for any refunds that may be required.
Accounting Standards Issued But Not Yetand Adopted
In AugustFebruary 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-15 “Statement of Cash Flows2016-02 “Leases (Topic 230): Classification of Certain Cash Receipts and Cash Payments”842)” (ASU 2016-15)2016-02). ASU 2016-15 provides specific2016-02 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 prior 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 are 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 rights-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 on eight cash flow classification issues, including debt prepaymentin Accounting Standards Codification (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 debt extinguishment costs and distributions receivedoperating 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 equity method investees, to reduce diversity in practice.the associated lease component if certain conditions are present. ASU 2016-152016-02 is effective for interim and annual periods beginning after December 15, 2017. Early2018. We prospectively adopted ASU 2016-02 effective January 1, 2019, and did not adjust prior periods as permitted by ASU 2018-11 (See Note 3).
We completed our review of contracts to identify leases based on the modified definition of a lease and implemented changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption is permitted.of ASU 2016-15 requires2016-02. We implemented a retrospective transition.financial lease accounting system to assist management in the accounting for leases upon adoption. The most significant changes to our financial statements as a result of adopting ASU 2016-02 relate to the recognition of a $91.3 million lease liability and offsetting right-of-use asset in our Condensed Consolidated Balance Sheetfor operating leases. We doalso 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 expect ASU 2016-15 to have a material impact on our consolidated financial statements.separate lease and non-lease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.
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.We plan to adopt as of January 1, 2020. We anticipate that ASU 2016-13 requires varying transition methods for the different categories of amendments. Wewill primarily apply to our trade receivables. While we do not expect ASU 2016-13 to have a significant financial impact, we are currently developing additional processes, procedures and internal controls in order to make the necessary credit loss assessments and required disclosures.

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 Condensed Consolidated Statement of Comprehensive Income.

Contract Liabilities
The following table presents a reconciliation of our contract liabilities:
  Year to Date March 31, 2019
 (Thousands)
Balance at beginning of period $236,730
Payments received and deferred 
Recognized in revenue (2,638)
Balance at end of period $234,092

The following table presents the amount of the contract liabilities balance as of March 31, 2019, expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:
 (Thousands)
2019 (remainder)$7,928
202010,568
202110,566
202210,566
202310,566
Thereafter183,898
Total$234,092
Remaining Performance Obligations
The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of March 31, 2019. These primarily include reservation charges on contracted capacity on our consolidated financial statements.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, net of estimated reserve for refund, 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. 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). Certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligations as of March 31, 2019, do 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.
In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes
 (Thousands)
2019 (remainder)$1,637,961
20202,060,759
20211,970,683
20221,673,295
20231,442,724
Thereafter13,219,316
Total$22,004,738
Accounts Receivable
Receivables from contracts with customers are included within Receivables - Trade and other and Receivables - Affiliates and receivables that are not related to contracts with customers are included with Receivables - Advances to affiliate in our Condensed Consolidated Balance Sheet. At March 31, 2019 and December 31, 2018, Receivables - Trade and other includes $13.8 million and $10.4 million, respectively, of receivables not related to contracts with customers.
3. LEASES
We are a comprehensive newlessee through noncancellable lease accounting model. ASU 2016-02 clarifies the definitionagreements for property and equipment consisting primarily of a lease, requires a dual approach to lease classification similar to current lease classifications,buildings, land, vehicles, and causes lessees toequipment used in both our operations and administrative functions. We recognize leases on the balance sheet as a lease liability with a correspondingan offsetting right-of-use asset in our Condensed Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. As an accounting policy, we have elected to combine lease and non-lease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset. ASU 2016-02
Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one to 15 years, but a certain land lease has a term of 108 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is effectivenot known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for interimone or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods 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 existingtermination provisions, when at or entered intoour sole election, will be reasonably certain of being exercised. Periods after the beginninginitial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the earliest comparative period presented in the financial statements. We 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.lease term. Additionally, we have identified possible financial systemelected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and internal control changes necessarythe offsetting right-of-use asset.
We used judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available.


 Three Months Ended 
 March 31, 2019
 (Thousands)
Lease Cost: 
Operating lease cost$2,502
Short-term lease cost
Variable lease cost1,392
Total lease cost$3,894
  
Cash paid for amounts included in the measurement of operating lease liabilities$2,388
  
 March 31, 2019
 (Thousands)
Other Information: 
Right-of-use assets$89,824
Operating lease liabilities: 
Current (included in Accrued liabilities in our Condensed Consolidated Balance Sheet)
$3,482
Lease liability$85,759
Weighted-average remaining lease term - operating leases (years)15
Weighted-average discount rate - operating leases5%
As of March 31, 2019, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for adoption. We currently anticipate utilizing a modified retrospective transition uponeach of the adoption of ASC 606 as of January 1, 2018.years ended December 31:
 (Thousands)
2019 (remainder)$6,540
20207,367
20219,448
20229,431
20239,435
Thereafter86,075
Total future lease payments128,296
Less amount representing interest39,055
Total obligations under operating leases$89,241

2.4. CONTINGENT LIABILITIES AND COMMITMENTS
Rate Matters
General rate case (Docket No. RP06-569)RP18-1126) On August 31, 2006,2018, we submitted to the Federal Energy Regulatory Commission (FERC)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 principally designed to recover increased costs. The rates becamebe effective March 1, 2007,2019, subject to refund and the outcome of a hearing. All issues in this proceedinghearing, 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 thethat rates for service under our WSS-OA storagecertain services that were proposed as overall rate schedule, which was implementeddecreases 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. On March 18, 2019, the FERC accepted our motion to place the rates that were suspended by the September 28, 2018 order into effect on March 1, 2007. Following2019, subject to refund. We have provided a hearing,reserve for rate refunds which we believe is adequate for any refunds that may be required.
Notice of Inquiry (Docket No. PL19-4-000) On March 21, 2019, the FERC issued an opinion approving our proposed incremental rate design,a Notice of Inquiry (NOI) in Docket No. PL19-4-000, seeking comments regarding whether and, subsequently denied requestsif so, how FERC should revise its policies for rehearing of that approval. On February 21, 2014,

determining the U. S.base return on equity (ROE) used in setting rates charged by jurisdictional public utilities. FERC also seeks comment on, among other things, whether FERC should change its ROE policies for interstate natural gas and oil pipelines to align with is policy for electric public utilities. FERC's action follows a decision from the United States Court of Appeals for the D.C.District of Columbia Circuit, (D.C. Circuit) issued an opinion thatwhich vacated and remanded a series of earlier FERC orders establishing a new base ROE for certain electric transmission owners. Following that decision, FERC proposed in the FERC's order becauseremanded proceedings that it rely on four financial models to establish ROEs for the FERC did not adequately supportaffected utilities rather than rely primarily on its conclusions. On March 17, 2016, the FERC issued an order addressing the issues raised by the D.C. Circuit's opinion.long-used, two-step Discounted Cash Flow model. In the March 17 order,NOI, FERC poses a series of questions and invites comments on this proposed new approach, including whether it should apply the FERC reversed its prior opinionnew approach to future proceedings involving interstate natural gas and found that Transco's incremental rate design is unjust and unreasonable. The FERC directed Transcooil pipeline ROEs. Comments in response to design its WSS-OA ratesthe NOI are due 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 consistentJune 26, 2019, with the March 17 order, and began charging those rates beginning April 19, 2016.reply comments due on July 26, 2019. We also filed a request for rehearing of the March 17 order. On October 4, 2017, the FERC issued an order denying all requests for rehearing of the March 17 order, accepting our April 18, 2016 compliance filing, and directing us to make refunds. As of September 30, 2017, we have accrued a liability for refunds of $19.3 million in Payables - Trade and other in the accompanying

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.currently are monitoring this proceeding.
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 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 liabilitycontractors' insurance policy.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 $6$5 million to $8 million (including$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. 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 September 30, 2017March 31, 2019, we had a balance of approximately $3.9$3.2 million for the expense portion of these estimated costs, $2.1$1.5 million recorded in Accrued liabilities and $1.8$1.7 million recorded in Other Long-Term Liabilities - Other in the accompanying Condensed Consolidated Balance Sheet. At December 31, 20162018, we had a balance of approximately $4.2$3.5 million for the expense portion of these estimated costs, $2.1$1.5 million

recorded in Accrued liabilities and $2.1$2.0 million 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$5 million to $8$7 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

In March 2008, theThe EPA promulgated aand various state regulatory agencies routinely promulgate and propose new lowerrules, 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, 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 Standard (NAAQS)Standards for ground-level ozone. In May 2012, the EPA completed designation of new eight-hour ozone non-attainment areas. Several of our facilities are located in 2008 ozone non-attainment areas. To date, no federal actions have been proposed to mandate additional emission controls at these facilities. Pursuant to 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, 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 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'srule’s implementation as the reductionit will trigger additional federal and state regulatory actions that may impact our operations. As aImplementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Total property, plant and equipment, is expected to increase.net in the Condensed Consolidated Balance Sheet for both new and existing facilities in affected areas. 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 area in the country is violating the 2010 NO2 NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” However, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ assessment of NO2 compliance, we are unable toreasonably estimate the cost of additions that may be required to meet the regulations at this regulation.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. 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.
3.5. DEBT AND FINANCING ARRANGEMENTS
Credit Facility
We, along with WPZWilliams and Northwest Pipeline LLC (Northwest) (the “borrowers”), are party to a credit agreementCredit 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 capacitycommitments of $1.0 billion are, subject to the $500 million borrowing sublimit applicable to us and Northwest, available to WPZ under this credit facility is $1.125 billion. We

are able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers.borrowers. At September 30, 2017,March 31, 2019, no letters of credit have been issued and no 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 September 30, 2017, noMarch 31, 2019, Williams had $1.0 billion of outstanding commercial paper was outstanding under the commercial paper program.paper.

Other Financing ObligationObligations
Dalton Expansion Project
During the constructionfirst quarter of our Dalton Expansion Project,2019, we received an additional $0.7 million of funding from a partnerco-owner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. Amounts received were recordedThis additional funding is reflected in Advances for construction costsLong-Term Debt on our Condensed Consolidated Balance Sheet. Upon placingAt March 31, 2019, 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 payableis $258.3 million, and the amount included in Long-term debt due within one year on our Condensed Consolidated Balance Sheet for this financing obligation is $1.9 million.
Atlantic Sunrise Project
During the first quarter of 2019, we received an additional $7.2 million of funding from a co-owner for its proportionate share of construction costs related to our partner over an expected term of 35 years. 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 courseits undivided ownership interest in certain parts of the capacity agreement. Theproject. This additional funding is reflected in Long-Term Debt on our Condensed Consolidated Balance Sheet. At March 31, 2019, the amount included in Long-Term Debt on our Condensed Consolidated Balance Sheet for this financing obligation maturesis $797.4 million, and the amount 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 on our Condensed Consolidated Balance Sheet for this financing obligation is $13.9 million.
Long-Term Debt Due Within One Year
The long-term debt due within one year at September 30, 2017March 31, 2019 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.obligations.
4.6. 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 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, 2013,2019, the annual funding obligation is approximately $36.4$35.9 million, with deposits made monthly.
Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions): 
September 30, 2017 December 31, 2016March 31, 2019 December 31, 2018
Amortized
Cost Basis
 
Fair
Value
 
Amortized
Cost Basis
 
Fair
Value
Amortized
Cost Basis
 
Fair
Value
 
Amortized
Cost Basis
 
Fair
Value
Cash and Money Market Funds$8.5
 $8.5
 $5.0
 $5.0
Money Market Funds$27.8
 $27.8
 $21.7
 $21.7
U.S. Equity Funds35.9
 47.7
 29.4
 36.5
50.5
 68.9
 46.4
 56.8
International Equity Funds20.7
 23.7
 19.2
 18.6
23.8
 25.6
 21.9
 21.4
Municipal Bond Funds46.8
 47.1
 36.7
 36.3
50.1
 50.5
 50.1
 49.6
Total$111.9
 $127.0
 $90.3
 $96.4
$152.2
 $172.8
 $140.1
 $149.5


5.7. 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 and from affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
 

     Fair Value Measurements Using     Fair Value Measurements Using
 
Carrying
Amount
 Fair Value 
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level  1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Carrying
Amount
 Fair Value 
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level  1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 (Millions) (Millions)
Assets (liabilities) at September 30, 2017:          
Assets (liabilities) at March 31, 2019:          
Measured on a recurring basis:                    
ARO Trust investments $127.0
 $127.0
 $127.0
 $
 $
 $172.8
 $172.8
 $172.8
 $
 $
                    
Additional disclosures:                    
Long-term debt, including current portion (2,449.0) (3,051.1) 
 (3,051.1) 
 (4,019.1) (5,034.0) 
 (5,034.0) 
                    
Assets (liabilities) at December 31, 2016:          
Assets (liabilities) at December 31, 2018:          
Measured on a recurring basis:                    
ARO Trust investments $96.4
 $96.4
 $96.4
 $
 $
 $149.5
 $149.5
 $149.5
 $
 $
                    
Additional disclosures:                    
Long-term debt (2,210.8) (2,507.5) 
 (2,507.5) 
Long-term debt, including current portion (4,014.4) (4,785.5) 
 (4,785.5) 
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 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 Note 46 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 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 35 - 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 ninethree months ended September 30, 2017March 31, 2019 or 20162018.
6.8. TRANSACTIONS WITH AFFILIATES
We are a participant in WPZ’sWilliams' cash management program, and we receive advances from and make advances to and receive advances from WPZ.Williams. At September 30, 2017 and DecemberMarch 31, 20162019, our advances from Williams totaled approximately $86.6 million and is classified as Payables - Advances from affiliates in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2018, our advances to WPZWilliams totaled approximately $299.133.0 million and $811.7 million, respectively. These advances are represented by demand notes and areis classified as Receivables - Advances to affiliate in the accompanying Condensed Consolidated Balance Sheet. Advances are stated at the historical

carrying amounts. Interest income isand expense are 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 September 30, 2017March 31, 2019, the interest rate was 0.912.33 percent.
Included in Operating Revenues in the accompanying Condensed Consolidated Statement of Comprehensive Income are revenues received from affiliates of $2.5$3.3 million and $8.9$1.8 million for the three and nine months ended September 30, 2017March 31,

2019, respectively, and $4.8 million and $8.9 million for the three and nine months ended September 30, 2016,2018, 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 Comprehensive Income are cost of gas purchased from affiliates of $1.0$1.6 million and $2.9$1.9 million for the three and nine months ended September 30, 2017March 31, 2019, respectively, and $1.8 million and $3.3 million for the three and nine months ended September 30, 2016,2018, 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 $91.4$92.2 million and $261.1$91.5 million in the three and nine months ended September 30, 2017March 31, 2019, respectively and $78.4 million and $234.7 million in the three and nine months ended September 30, 2016,2018, 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 Comprehensive 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$1.2 million and $2.7$1.0 million for the three and nine months ended September 30, 2017, respectively,March 31, 2019 and $1.0 million and $3.4 million for the three and nine months ended September 30, 2016,2018, respectively.
We made equity distributions totaling $330.0$176.0 million and $350.055.0 million during the ninethree months ended September 30, 2017March 31, 2019 and 20162018, respectively. During October 2017,April 2019, we made an additional distribution of $100.0$170.0 million. Our parent made contributions to us totaling $110.0 million and $372.0340.0 million in the ninethree months ended March 31, September 30, 2017 and 20162018, respectively, 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 distributionto 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 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.

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 20162018 Annual Report on Form 10-K and with the Condensed Consolidated Financial Statements and Notes contained in this Form 10-Q.
Filing of Rate Case
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. On March 18, 2019, the FERC accepted our motion to place the rates that were suspended by the September 28, 2018 order into effect on March 1, 2019, subject to refund. We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required.
Critical Accounting Estimates
In December 2017, Tax Reform was enacted, which, among other things, reduced the 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 $448.1 million as of March 31, 2019 and $450.2 million as of December 31, 2018. Effective March 1, 2019, we began amortizing this regulatory liability. 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.
RESULTS OF OPERATIONS
Operating Income and Net Income
Operating Income for the ninethree months ended September 30, 2017March 31, 2019 was $476.6290.3 million compared to $449.0198.0 million for the ninethree months ended September 30, 2016March 31, 2018. The increase in Operating Income of $27.6$92.3 million (6.1(46.6 percent) was primarily due to higher Natural gas transportation and Natural gas storagerevenues in the first ninethree months of 20172019 compared to the same period in 2016,2018, partly offset by an increase in Operating Costs and Expenses, as discussed below. Net Income for the ninethree months ended September 30, 2017March 31, 2019 was $440.9$229.7 million compared to $384.5$179.9 million for the ninethree months ended September 30, 2016.March 31, 2018. The increase in Net Income of $56.4$49.8 million (14.7(27.7 percent) was mostly attributable to the increase in Operating Income and a favorablepartially offset by an unfavorable change in net expenses in Other (Income) and Other Expenses, as discussed below.
Operating Revenues
Natural gas salestransportation for the three months ended March 31, 2019 increased $7.4$107.6 million (11.0(25.2 percent) for the nine months ended September 30, 2017 compared toover the same period in 2016.2018. The increase was primarily dueattributable to:
$110.6 million increase in transportation reservation revenues related to system management gas sales. System management gas salesnew incremental projects attributable to:
$97.2 million from our Atlantic Sunrise project placed in full service in October 2018;
$8.6 million from our Gulf Connector project placed in service in January 2019; and
$4.8 million from our Garden State project placed in full service in March 2018.
$4.3 million higher recoveries of electric power costs. Electric power costs are offsetrecovered from customers through transportation rates resulting in our cost of natural gas sold and therefore have no net impact on our operating income or results of operations.
Natural gas transportation for the nine months ended September 30, 2017 increased $74.4Partially offset by $6.0 million (7.1 percent) over the same period in 2016. The increase was primarily due to higher transportation reservationlower revenues related to new incremental projects of $88.4 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.Docket No. RP18-1126 rate decreases effective October 1, 2018.
Natural gas storage increased $14.5 million (16.4 percent) for the nine months ended September 30, 2017 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$24.1 million for the ninethree months ended September 30, 2017March 31, 2019 and $67.5$25.3 million for the comparable period in 20162018, our operating costs and expenses for the ninethree months ended September 30, 2017March 31, 2019 increased approximately $61.5$16.7 million (9.0(6.3 percent) from the comparable period in 20162018. This increase was primarily attributable to:
A $41.9$21.4 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 million (3.6(25.7 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 $4.3 million lower expense due to ARO-related depreciation;service;
A $6.0$1.5 million (4.8(11.5 percent) increase in Administrative and generalCost of natural gas transportation costs primarily resulting from $4.3 million higher electric power costs, partly offset by $2.7 million lower fuel costs;
Partially offset by $4.5 million (25.3 percent) decrease in Other expenses, net primarily due to higher allocated corporate expenses;a $1.7 million favorable change in the deferral of ARO related depreciation to a regulatory asset, and a $3.1 million favorable change in costs associated with pension and other postretirement benefits related to Docket No. RP18-1126; and
A $3.9$3.6 million (8.6(4.1 percent) decrease in Operation and maintenance costs primarily resulting from a $5.8 million decrease in contracted services mainly related to general maintenance and other testing on our pipeline, partly offset by a $2.9 million increase in Taxes - other than income taxes primarily due to higher ad valorem taxes as a result of additional assets placed into service.employee labor and related benefit costs.
Other (Income) and Other Expenses
Other (income) and other expenses for the ninethree months ended September 30, 2017March 31, 2019 had a favorablean unfavorable change of $28.8$42.5 million (44.7(234.8 percent) over the same period in 20162018. This is mostly due to ana $26.0 million increase inInterest expense primarily due to $20.6 million associated with other financing obligations and $9.0 million associated with our debt issuance in March 2018, partly offset by $3.8 million associated with our debt retirement in June 2018, and an unfavorable change of $17.9 million in Allowance for equity and borrowed funds used during construction (AFUDC) associated with capital expenditures on projects.

Pipeline Expansion Projects
Gulf Trace
The Gulf Trace Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 65 in St. Helena Parish, Louisiana westward to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. We placed the project into service on February 1, 2017, and it increased capacity by 1,200 Mdth/d.
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 will beis being constructed in phases, and all of the project expansion capacity will be leasedis dedicated to Sabal Trail. We placedTrail pursuant to a portion ofcapacity lease agreement. Phase I into service on June 14,was completed in 2017 and we placed the remainder of Phase I into service on July 11, 2017. Phase Iit 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 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 State
The Garden State Expansion Project involves 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. The project will be constructed in phases. The FERC certificate 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. We plan to place the project into service during 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 withplaced the FERC in August 2016 for approval of the project.project into service on January 4, 2019. The project will be constructed in two phases, and we plan to place both phases into service during the first half of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increaseincreased 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. We filed anOn April 20, 2018, the New York State Department of Environmental Conservation (NYSDEC) denied, without prejudice, Transco's application with the FERC in March 2017 for approval ofcertain 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 late 2019 or during the first halffourth quarter 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 withIn August 2018, we received approval from 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 withIn December 2018, we received approval from 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,mid-year 2020, 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.
South Louisiana Market
The South Louisiana Market Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to a new interconnection with a proposed chemical plant in St. James Parish, Louisiana. We expect to file an application with the FERC in August 2019 for approval of the project. We plan to place the project into service in the fourth quarter of 2022, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 202 Mdth/d.


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 thirdfirst quarter of 20172019 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, we entered into a Consent Order with the Georgia Department of Natural Resources, Environmental Protection Division (GEPD) pertaining to alleged violations of the Georgia Water Quality Control Act and associated rules arising from 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.
Other
The additional information called for by this item is provided in Note 24 of the Notes to Condensed Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item.

ITEM 1A.Risk Factors

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018, includes risk factors that could materially affect our business, financial condition, or future results. Those risk factors have not materially changed.






ITEM 6.Exhibits
The following instruments are included as exhibits to this report.
 
Exhibit
Number
 Description
   
2 
   
3.1 
   
3.2 
   
31.1* 
   
31.2* 
   
32** 
   
101.INS* XBRL Instance 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.
**Furnished herewith.

 


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:NovemberMay 2, 20172019By: /s/ Ted T. TimmermansKathleen R. Hambleton
    Ted T. TimmermansKathleen R. Hambleton
    Vice President, Controller and Chief Accounting Officer
    (Principal Accounting Officer)