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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 March 31, 2014
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)
 
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 or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
 
¨
Accelerated filer
 
¨
Non-accelerated filer
 
þ
Smaller reporting company
 
¨
 
 
 
 
 
 
 
 
 
 
 
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  þ
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.
 





TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC
Index
 
Forward Looking Statements
Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “assumes,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “guidance,” “outlook,” “in service date” or other similar expressions. These statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
Amounts and nature of future capital expenditures;
Expansion and growth of our business and operations;
Financial condition and liquidity;
Business strategy;
Cash flow from operations or results of operations;
Rate case filings;
Natural gas prices, supply and demand; and
Demand for our services.
Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will

1


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:
Availability of supplies, market demand, and volatility of prices;
Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
The strength and financial resources of our competitors and the effects of competition;
Whether we are able to successfully identify, evaluate and execute investment opportunities;
Development of alternative energy sources;
The impact of operational and development hazards and unforeseen interruptions;
Costs of, changes in, or the results of laws, government regulations (including safety and environmental regulations), environmental liabilities, litigation, and rate proceedings;
Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;
Changes in maintenance and construction costs;
Changes in the current geopolitical situation;
Our exposure to the credit risks of our customers and counterparties;
Risks related to financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of capital;
Risks associated with weather and natural phenomena including climate conditions;
Acts of terrorism, including cybersecurity threats and related disruptions; and
Additional risks described in our filings with the Securities and Exchange Commission (SEC).
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. 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, 2013.


2


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 
 March 31,
 
 
2014
 
2013
Operating Revenues:
 
 
 
 
Natural gas sales
 
$
27,568

 
$
24,571

Natural gas transportation
 
300,381

 
269,577

Natural gas storage
 
36,595

 
35,590

Other
 
1,118

 
1,324

Total operating revenues
 
365,662

 
331,062

 
 
 
 
 
Operating Costs and Expenses:
 
 
 
 
Cost of natural gas sales
 
27,568

 
24,571

Cost of natural gas transportation
 
11,203

 
10,854

Operation and maintenance
 
60,433

 
60,454

Administrative and general
 
47,134

 
47,023

Depreciation and amortization
 
69,909

 
67,693

Taxes — other than income taxes
 
12,282

 
11,626

Other expense, net
 
7,451

 
7,080

Total operating costs and expenses
 
235,980

 
229,301

 
 
 
 
 
Operating Income
 
129,682

 
101,761

 
 
 
 
 
Other (Income) and Other Expenses:
 
 
 
 
Interest expense
 
21,959

 
20,554

Allowance for equity and borrowed funds used during construction (AFUDC)
 
(2,982
)
 
(4,830
)
Equity in earnings of unconsolidated affiliates
 
(1,477
)
 
(1,258
)
Miscellaneous other (income) expenses, net
 
402

 
(1,680
)
Total other (income) and other expenses
 
17,902

 
12,786

 
 
 
 
 
Net Income
 
111,780

 
88,975

 
 
 
 
 
Other comprehensive income (loss):
 
 
 
 
Equity interest in unrealized gain (loss) on interest rate hedges (includes $84 for 2014 and $79 for 2013 of accumulated other comprehensive income reclassification for realized losses on interest rate hedges)
 
38

 
102

 
 
 
 
 
Comprehensive Income
 
$
111,818

 
$
89,077


See accompanying notes.


3


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

 
 
March 31,
2014
 
December 31,
2013
ASSETS
 
 
 
 
 
 
 
 
 
Current Assets:
 
 
 
 
Cash
 
$
146

 
$
113

Receivables:
 
 
 
 
Affiliates
 
932

 
2,601

Advances to affiliate
 
603,014

 
526,380

Trade and other
 
127,964

 
148,172

Transportation and exchange gas receivables
 
6,386

 
6,757

Inventories
 
51,611

 
47,532

Regulatory assets
 
42,000

 
37,520

Other
 
6,820

 
13,451

Total current assets
 
838,873

 
782,526

 
 
 
 
 
Investments, at cost plus equity in undistributed earnings
 
49,493

 
50,262

 
 
 
 
 
Property, Plant and Equipment:
 
 
 
 
Natural gas transmission plant
 
8,940,104

 
8,867,626

Less-Accumulated depreciation and amortization
 
3,131,335

 
3,090,234

Total property, plant and equipment, net
 
5,808,769

 
5,777,392

 
 
 
 
 
Other Assets:
 
 
 
 
Regulatory assets
 
252,633

 
256,612

Other
 
66,272

 
57,785

Total other assets
 
318,905

 
314,397

 
 
 
 
 
Total assets
 
$
7,016,040

 
$
6,924,577


(continued)




See accompanying notes.

4


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

 
 
March 31,
2014
 
December 31,
2013
LIABILITIES AND OWNER’S EQUITY
 
 
 
 
 
 
 
 
 
Current Liabilities:
 
 
 
 
Payables:
 
 
 
 
Affiliates
 
$
28,750

 
$
28,268

Trade and other
 
237,985

 
114,635

Transportation and exchange gas payables
 
2,165

 
3,599

Reserve for rate refunds
 

 
98,217

Accrued liabilities
 
147,021

 
153,263

Total current liabilities
 
415,921

 
397,982

 
 
 
 
 
Long-Term Debt
 
1,428,389

 
1,428,355

 
 
 
 
 
Other Long-Term Liabilities:
 

 

Asset retirement obligations
 
238,765

 
238,085

Regulatory liabilities
 
288,182

 
269,563

Other
 
5,680

 
5,307

Total other long-term liabilities
 
532,627

 
512,955

 
 
 
 
 
Contingent Liabilities and Commitments (Note 2)
 

 

 
 
 
 
 
Owner’s Equity:
 

 

Member’s capital
 
2,311,499

 
2,257,499

Retained earnings
 
2,327,824

 
2,328,044

Accumulated other comprehensive loss
 
(220
)
 
(258
)
Total owner’s equity
 
4,639,103

 
4,585,285

 
 
 
 
 
Total liabilities and owner’s equity
 
$
7,016,040

 
$
6,924,577





See accompanying notes.


5


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
 
 
Three months ended March 31,
 
 
2014
 
2013
Cash flows from operating activities:
 
 
 
 
Net income
 
$
111,780

 
$
88,975

Adjustments to reconcile net income to net cash provided by (used in) operating activities:
 
 
 
 
Depreciation and amortization
 
69,654

 
76,466

Allowance for equity funds used during construction (equity AFUDC)
 
(2,182
)
 
(3,366
)
Changes in operating assets and liabilities:
 
 
 
 
Receivables — affiliates
 
1,669

 
(268
)
   — trade and other
 
20,174

 
(6,116
)
Transportation and exchange gas receivable
 
371

 
(1,872
)
Inventories
 
(4,079
)
 
(4,196
)
Payables — affiliates
 
482

 
(5,473
)
     — trade
 
(59,215
)
 
(9,242
)
Accrued liabilities
 
(10,131
)
 
11,735

Reserve for rate refunds
 
20,019

 
10,574

Asset retirement obligation removal costs
 
(3,753
)
 
(1,847
)
Other, net
 
14,822

 
4,641

Net cash provided by operating activities
 
159,611

 
160,011

 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
Cash distributions to parent
 
(112,000
)
 
(65,000
)
Cash contributions from parent
 
54,000

 
55,000

Other, net
 
4,143

 
7,542

Net cash used in financing activities
 
(53,857
)
 
(2,458
)
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
Property, plant and equipment additions, net of equity AFUDC*
 
(23,365
)
 
(85,816
)
Disposal of property, plant and equipment, net
 
5,241

 
1,423

Advances to affiliate, net
 
(76,634
)
 
(73,178
)
Return of capital from unconsolidated affiliates
 
301

 

Purchase of ARO Trust investments
 
(28,851
)
 
(8,938
)
Proceeds from sale of ARO Trust investments
 
16,851

 
8,577

Other, net
 
736

 
333

Net cash used in investing activities
 
(105,721
)
 
(157,599
)
 
 
 
 
 
Increase (decrease) in cash
 
33

 
(46
)
Cash at beginning of period
 
113

 
185

Cash at end of period
 
$
146

 
$
139

 
 
 
 
 
*       Increase to property, plant and equipment
 
$
(86,979
)
 
$
(109,985
)
Changes in related accounts payable and accrued liabilities
 
63,614

 
24,169

Property, plant and equipment additions, net of equity AFUDC
 
$
(23,365
)
 
$
(85,816
)
See accompanying notes.

6


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 owned, through Williams Partners Operating LLC (WPO), by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). At March 31, 2014, Williams holds an approximate 66 percent interest in WPZ, comprised of an approximate 64 percent limited partner interest and all of WPZ’s 2 percent general partner interest.
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 March 31, 2014 and December 31, 2013 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 $2.3 million and $2.2 million in the three months ended March 31, 2014 and March 31, 2013, respectively. Included in the distributions is a $0.3 million return of capital from Pine Needle in 2014.
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 SEC 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 2013 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.
Certain prior period amounts reported within Total operating costs and expenses in the Condensed Consolidated Statement of Comprehensive Income have been reclassified to conform to the current presentation. The effect of the correction decreased Depreciation and amortization and increased Other expense, net by $9.0 million related to the reclassification of asset retirement obligation (ARO), with no net impact on Total operating costs and expenses, Operating Income or Net Income.
2. CONTINGENT LIABILITIES AND COMMITMENTS.
Rate Matters.
General rate case (Docket No. RP12-993) On August 31, 2012, we submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in our Docket No. RP06-569 rate proceeding (see below) which required us to file a rate case no later than August 31, 2012. On September 28, 2012, the FERC issued an order accepting our filing subject to the outcome of a hearing. The rates for certain services that were proposed as overall rate decreases became effective October 1, 2012, without suspension. The increased rates became effective March 1, 2013, subject to refund and the outcome of a hearing. On August 27, 2013, after reaching an agreement in principle with the participants, we filed a stipulation and agreement (Agreement) proposing to resolve all issues in this proceeding without the need for a hearing. On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement became effective

7


on March 1, 2014 and refunds of approximately $118 million were issued on April 18, 2014. We previously provided a reserve for the refunds, which was reclassified, from Reserve for rate refunds to Payable - Trade and other on the accompanying Condensed Consolidated Balance Sheet at March 31, 2014.
General rate case (Docket No. RP06-569) On August 31, 2006, we submitted to the FERC a general rate filing principally designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.
The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under one of our storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that our proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Certain parties sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one of the parties filed an appeal in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). On February 21, 2014, the D.C. Circuit issued an opinion that vacated and remanded the FERC's order because the FERC did not adequately support its conclusions. We intend to continue to pursue approval of our proposed rate design. If we are unsuccessful, we believe any refunds would not be material to our results of operations.
Environmental Matters.
We have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have responded 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 be spent over the next three to five 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 March 31, 2014, we had a balance of approximately $3.7 million for the expense portion of these estimated costs recorded in current liabilities ($2.3 million) and other long-term liabilities ($1.4 million) in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2013, we had a balance of approximately $4.1 million for the expense portion of these estimated costs recorded in current liabilities ($2.3 million) and other long-term liabilities ($1.8 million) in the accompanying Condensed Consolidated Balance Sheet.
Although we discontinued the use of lubricating oils containing polychlorinated biphenyls (PCBs) in the 1970s, we have discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. We have worked closely with the EPA and state regulatory authorities regarding PCB issues, and we have a program to assess and remediate such conditions where they exist. In addition, we commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $6 million to $8 million range discussed above.
We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $6 million to $8 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.
In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground level ozone to ensure that the standards were clearly grounded in science, and were protective of both public health and the

8


environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. In September 2011, the EPA announced that it was proceeding with required actions to implement the 2008 ozone standard and area designations. In May 2012, the EPA completed designation of new eight-hour ozone non-attainment areas. Several Transco facilities are located in 2008 ozone non-attainment areas; however, each facility has been previously subjected to federal and/or state emission control requirements implemented to address preceding ozone standards. To date, no new federal or state actions have been proposed to mandate additional emission controls at these facilities. At this time, it is unknown whether future federal or state regulatory actions associated with implementation of the 2008 ozone standard will impact our operations and increase the cost of additions to property, plant and equipment. Until any additional federal or state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet this new regulation.
On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” Also, at that time, the EPA noted its plan to deploy an expanded NO2 monitoring network beginning in 2013. However, on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO2 NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this regulation.
We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Condensed Consolidated Balance Sheet until collected through rates. At March 31, 2014, we had a balance of approximately $1.5 million of uncollected environmental related regulatory assets recorded in current assets ($1.2 million) and other assets ($0.3 million) in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2013, we had a balance of approximately $1.8 million of uncollected environmental related regulatory assets recorded in current assets ($1.2 million) and other assets ($0.6 million) in the accompanying Condensed Consolidated Balance Sheet.
By letter dated September 20, 2007, the EPA required us to provide information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Federal Clean Air Act (Act). By January 2008, we responded with the requested information. By Notices of Violation (NOVs) dated March 28, 2008, the EPA found us to be in violation of the requirements of the Act with respect to these compressor stations. We met with the EPA in May 2008 to discuss the allegations contained in the NOVs; in June 2008, we submitted to the EPA a written response denying the allegations. The EPA has requested additional information pertaining to these compressor stations and in May 2011, we submitted information in response to the EPA’s latest request. In August, 2010, the EPA requested, and we provided, similar information for a compressor station in Maryland. Since 2011, we have not received any additional requests from the EPA for information related to these facilities.
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

9


parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.
3. DEBT AND FINANCING ARRANGEMENTS.
Credit Facility.
We along with WPZ and Northwest Pipeline LLC (Northwest) are co-borrowers under a $2.5 billion credit facility. Total letter of credit capacity available to WPZ under the $2.5 billion credit facility is $1.3 billion. We may borrow up to $500 million under the credit facility to the extent not otherwise utilized by WPZ and Northwest. At March 31, 2014, no letters of credit have been issued and no loans are outstanding under our credit facility.
WPZ participates in a commercial paper program and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. At March 31, 2014, there was no outstanding commercial paper.
4. ARO TRUST.
Available-for-Sale Investments.
We are entitled to collect in rates the amounts necessary to fund our ARO. We deposit monthly, into an external trust account, the revenues specifically designated for ARO. We established the ARO trust account (ARO Trust) on June 30, 2008. The ARO Trust carries a moderate risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.
Effective March 1, 2013, the annual funding obligation is approximately $36.4 million, with deposits made monthly.
Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions): 
 
March 31, 2014
 
December 31, 2013
 
Amortized
Cost Basis
 
Fair
Value
 
Amortized
Cost Basis
 
Fair
Value
Cash and Money Market Funds
$
13.9

 
$
13.9

 
$
6.5

 
$
6.5

U.S. Equity Funds
6.7

 
9.3

 
8.0

 
11.1

International Equity Funds
5.7

 
6.4

 
4.2

 
4.9

Municipal Bond Funds
15.2

 
15.4

 
10.2

 
10.2

Total
$
41.5

 
$
45.0

 
$
28.9

 
$
32.7








5. FAIR VALUE MEASUREMENTS.
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities.
 
 
 
 
 
 
 
Fair Value Measurements Using
 
 
Carrying
Amount
 
Fair Value
 
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level  1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
 
(Millions)
Assets (liabilities) at March 31, 2014:
 
 
 
 
 
 
 
 
 
 
Measured on a recurring basis:
 
 
 
 
 
 
 
 
 
 
ARO Trust investments
 
$
45.0

 
$
45.0

 
$
45.0

 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
Additional disclosures:
 
 
 
 
 
 
 
 
 
 
Notes receivable
 
5.6

 
5.6

 

 
5.6

 

Long-term debt
 
(1,428.4
)
 
(1,550.3
)
 

 
(1,550.3
)
 

 
 
 
 
 
 
 
 
 
 
 
Assets (liabilities) at December 31, 2013:
 
 
 
 
 
 
 
 
 
 
Measured on a recurring basis:
 
 
 
 
 
 
 
 
 
 
ARO Trust investments
 
$
32.7

 
$
32.7

 
$
32.7

 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
Additional disclosures:
 
 
 
 
 
 
 
 
 
 
Notes receivable
 
6.3

 
6.3

 

 
6.3

 

Long-term debt
 
(1,428.4
)
 
(1,512.9
)
 

 
(1,512.9
)
 

Fair Value of Methods.

10


The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash and short-term financial assets (advances to affiliate) that have variable interest rates — The carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments.
ARO Trust investments — We deposit a portion of our collected rates, pursuant to the Agreement in the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, 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 4 for more information regarding the ARO Trust.
Notes receivable The disclosed fair value of our notes receivable is determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in Trade and other receivables, and the noncurrent portion is reported in Other Assets-Other in the Condensed Consolidated Balance Sheet.
Long-term debt — The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the three months ended March 31, 2014 or 2013.

6. TRANSACTIONS WITH AFFILIATES.
We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At March 31, 2014 and December 31, 2013, our advances to WPZ totaled approximately $603.0 million and $526.4 million, respectively. These advances are represented by demand notes and are classified as Current Assets in 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’s excess cash at the end of each month. At March 31, 2014, the interest rate was 0.01 percent.
Included in our Operating Revenues in the accompanying Condensed Consolidated Statement of Comprehensive Income are revenues received from affiliates of $1.3 million and $5.9 million for the three months ended March 31, 2014 and 2013, 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 our Cost of natural gas sales in the accompanying Condensed Consolidated Statement of Comprehensive Income are cost of gas purchased from affiliates of $3.4 million and $2.4 million, for the three months ended March 31, 2014 and 2013, 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 $75.2 million and $74.6 million in the three months ended March 31, 2014 and

11


2013, respectively, for these services. Such expenses are primarily included in Administrative and general and Operation and maintenance expenses in the accompanying Condensed Consolidated Statement of Comprehensive Income.
We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $1.3 million and $1.5 million for the three months ended March 31, 2014 and 2013, respectively. In the first quarter of 2014, pursuant to construction agreements, we received pre-payments from Williams Field Services Group, LLC of $4.2 million associated with capital projects.
We made equity distributions to WPO totaling $112.0 million and $65.0 million during the three months ended March 31, 2014 and 2013, respectively. During April 2014, we made an additional distribution to WPO of $123.0 million. WPO made contributions to us totaling $54.0 million and $55.0 million in the three months ended March 31, 2014 and 2013, respectively, to fund a portion of our expenditures for additions to property, plant and equipment. In April 2014, WPO made an additional $40.0 million contribution to us.
7. OTHER.
For the three months ended March 31, 2014, we capitalized $1.5 million of project feasibility cost associated with the Hillabee Expansion Project and the Atlantic Sunrise Project, which had been expensed in prior periods in Other expense, net, upon determining that the projects were probable of development.


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 2013 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 three months ended March 31, 2014 was $129.7 million compared to $101.8 million for the three months ended March 31, 2013. Net income for the three months ended March 31, 2014 was $111.8 million compared to $89.0 million for the three months ended March 31, 2013. The increase in Operating income of $27.9 million (27.4 percent) was primarily due to higher Natural gas transportation revenues in the first three months of 2014 compared to the same period in 2013, partly offset by an increase in Operating Costs and Expenses, as discussed below. The increase in Net income of $22.8 million (25.6 percent) was mostly attributable to the increase in Operating income partly offset by an unfavorable change in net expenses in Other (Income) and Other Expenses, as discussed below.
Sales Revenues.
Operating revenues: Natural gas sales increased $3.0 million (12.2 percent) for the three months ended March 31, 2014 compared to the same period in 2013. The increase was due to higher cash-out sales. Cash-out sales are offset in our cost of natural gas sold and therefore had no impact on our operating income or results of operations.
Transportation Revenues.
Operating revenues: Natural gas transportation for the three months ended March 31, 2014 increased $30.8 million (11.4 percent) over the same period in 2013. The increase was partly due to the implementation of new rates in March 2013 which were higher as compared to the rates provided in the settlement of the prior rate proceeding. Also contributing to the favorable variance were higher transportation reservation revenues related to new incremental projects of $16.6 million ($13.3 million from our Northeast Supply Link project placed in service in August 2013 and $3.3 million from our Mid-South project Phase 2 placed in service in June 2013).
Operating Costs and Expenses.
Excluding the Cost of natural gas sales, which is directly offset in revenues, of $27.6 million for the three months ended March 31, 2014 and $24.6 million for the comparable period in 2013, our operating costs and expenses for the three months ended March 31, 2014 increased approximately $3.7 million (1.8 percent) from the comparable period in 2013. This increase was primarily attributable to a $2.2 million increase in Depreciation and amortization costs due to expansion projects placed into service in mid-2013.
Other (Income) and Other Expenses.
Other (income) and other expenses for the three months ended March 31, 2014 had an unfavorable change of $5.1 million (39.8 percent) over the same period in 2013 primarily due to $1.8 million decrease in AFUDC, $1.5 million lower amount of reimbursements for tax gross-up related to projects and $1.4 million increase in interest expense primarily due to interest on rate reserves.
Filing of Rate Case.
On August 31, 2012, we filed a general rate case with the FERC for an overall increase in rates. In September 2012, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2013, subject to refund and the outcome of a hearing. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2012, and are not subject to refund. On August 27, 2013, after reaching an agreement in principle with the participants, we filed an Agreement proposing to resolve all issues in this proceeding without the need for a hearing. On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement became effective March 1, 2014 and refunds of approximately $118 million were issued on April 18, 2014. We had previously provided a reserve for the refunds, which was reclassified, from Reserve for rate refunds to Payable - Trade and other on the accompanying Condensed Consolidated Balance Sheet at March 31, 2014.

12


Capital Expenditures.
Our capital expenditures for the three months ended March 31, 2014 were $23.4 million, compared to $85.8 million for the three months ended March 31, 2013. The $62.4 million decrease is primarily due to lower spending on expansion projects in 2014. Our capital expenditures estimate for 2014 and future capital projects are discussed in our 2013 Annual Report on Form 10-K. The following describes those projects and certain new capital projects proposed by us.
Rockaway Delivery Lateral
The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. We filed an application with the FERC in January 2013 for approval of the project. We plan to place the project into service during the fourth quarter of 2014, assuming timely receipt of all necessary regulatory approvals, and the capacity of the lateral is expected to be 647 Mdth/d.
Northeast Connector Project
The Northeast Connector Project involves an expansion of our existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. We filed an application with the FERC in April 2013 for approval of the project. We plan to place the project into service during the fourth quarter of 2014, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 100 Mdth/d.
Mobile Bay South III
The Mobile Bay South III Project involves an expansion of the Mobile Bay line south from Station 85 in west central Alabama to delivery points along the line. In April 2014, we received approval from the FERC for the project. We plan to place the project into service during the second quarter of 2015, and it is expected to increase capacity on the line by 225 Mdth/d.
Virginia Southside
The Virginia Southside Project involves an expansion of our existing natural gas transmission system from the Zone 6 Station 210 Pooling Point in New Jersey to Dominion Virginia Power’s proposed power station in Brunswick County, Virginia, and both our Cascade Creek interconnection with East Tennessee Natural Gas and our Pleasant Hill delivery point to Piedmont Natural Gas Company, Inc. in North Carolina. In November 2013, we received approval from the FERC for the project. We plan to place the project into service during the third quarter of 2015, and it is expected to increase capacity by 270 Mdth/d.
Leidy Southeast
The Leidy Southeast Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line in Pennsylvania to the Station 85 pooling points in Alabama. We filed an application with the FERC in September 2013 for approval of the project. We plan to place the project into service during the fourth quarter of 2015, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 525 Mdth/d.
Rock Springs Expansion
The Rock Springs Expansion Project involves an expansion of our existing natural gas transmission system southbound from the Zone 6 Station 210 Pooling Point in New Jersey along with a new eleven mile lateral to Old Dominion Electric Cooperative's proposed Wildcat Point generation facility in Cecil County, Maryland. We plan to file an application with the FERC in the second quarter of 2014 for approval of the project. We plan to place the project into service during the third quarter of 2016, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 192 Mdth/d.
Hillabee Expansion
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 proposed new interconnection with Sabal Trail Transmission's system in Tallapoosa County, Alabama. The project will be constructed in phases and all of the project expansion capacity will be leased to Sabal Trail Transmission. We plan to file an application with the FERC in the fourth quarter of 2014 for approval of the initial phases of the project. We plan to place the initial phases of the project into service during the



second quarter of 2017 and 2020, assuming timely receipt of all necessary regulatory approvals, and together they are expected to increase capacity by 1,025 Mdth/d.
Gulf Trace Expansion
The Gulf Trace Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide firm transportation from Station 65 in St. Helena Parish, Louisiana westward to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. We plan to file an application with the FERC in the fourth quarter of 2014 for approval of the project. We plan to place the project into service during the first half of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 1,200 Mdth/d.
Dalton Lateral
The Dalton Lateral Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide firm transportation from the Zone 6 Station 210 Pooling Point in New Jersey to markets in northwest Georgia. We plan to file an application with the FERC in the first quarter of 2015 for approval of the project. We plan to place the project into service in 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 448 Mdth/d.
Atlantic Sunrise Project
The Atlantic Sunrise Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide firm transportation from the northeastern Marcellus producing area to markets along our mainline as far south as Station 85 in Alabama. We plan to file an application with the FERC in the second quarter of 2015 for approval of the project. We plan to place the project into service during the second half of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 1,700 Mdth/d.





ITEM 4.
Controls and Procedures.
Our management, including our Senior Vice President — Atlantic-Gulf and our Vice President and Chief Accounting Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) or our internal controls 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 — Atlantic-Gulf and our Vice President and Chief Accounting Officer. Based upon that evaluation, our Senior Vice President — Atlantic-Gulf and our Vice President and Chief Accounting Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Changes in Internal Controls Over Financial Reporting
There have been no changes during the first quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.

PART II — OTHER INFORMATION.

ITEM 1.
Legal Proceedings.
The information called for by this item is provided in Note 2 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.


15


ITEM 6.
Exhibits.
The following instruments are included as exhibits to this report.
 
Exhibit
Number
 
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 report Form 10-K 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 report Form 10-K 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 Form 10-Q 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.
 
 
 
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.

 


16



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:
May 1, 2014
By:
 
/s/ Jeffrey P. Heinrichs
 
 
 
 
Jeffrey P. Heinrichs
 
 
 
 
Controller
(Principal Accounting Officer)




EXHIBIT INDEX.

Exhibit
Number
 
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 Form 10-K 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 Form 10-K 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 Form 10-Q 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.
 
 
 
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.