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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 September 30, 2013
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;
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 strategy and 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, 2012.


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 
 September 30,
 
Nine months ended 
 September 30,
 
 
2013
 
2012
 
2013
 
2012
Operating Revenues:
 
 
 
 
 
 
 
 
Natural gas sales
 
$
27,282

 
$
15,828

 
$
87,866

 
$
36,691

Natural gas transportation
 
268,426

 
251,691

 
808,002

 
761,659

Natural gas storage
 
35,736

 
34,714

 
107,243

 
105,171

Other
 
811

 
724

 
3,085

 
3,079

Total operating revenues
 
332,255

 
302,957

 
1,006,196

 
906,600

 
 
 
 
 
 
 
 
 
Operating Costs and Expenses:
 
 
 
 
 
 
 
 
Cost of natural gas sales
 
27,282

 
15,828

 
87,866

 
36,691

Cost of natural gas transportation
 
3,056

 
8,104

 
22,053

 
27,264

Operation and maintenance
 
70,294

 
79,991

 
194,008

 
219,518

Administrative and general
 
43,747

 
42,443

 
135,767

 
131,225

Depreciation and amortization
 
66,989

 
66,693

 
198,148

 
199,068

Taxes — other than income taxes
 
11,318

 
11,133

 
33,879

 
33,660

Other (income) expense, net
 
12,562

 
7,753

 
24,750

 
31,214

Total operating costs and expenses
 
235,248

 
231,945

 
696,471

 
678,640

 
 
 
 
 
 
 
 
 
Operating Income
 
97,007

 
71,012

 
309,725

 
227,960

 
 
 
 
 
 
 
 
 
Other (Income) and Other Expenses:
 
 
 
 
 
 
 
 
Interest expense
 
21,416

 
21,132

 
62,716

 
68,518

Allowance for equity and borrowed funds used during construction (AFUDC)
 
(5,002
)
 
(5,886
)
 
(15,352
)
 
(14,468
)
Equity in earnings of unconsolidated affiliates
 
(1,493
)
 
(2,127
)
 
(4,234
)
 
(5,395
)
Miscellaneous other (income) expenses, net
 
(1,632
)
 
(2,069
)
 
(4,747
)
 
(4,121
)
Total other (income) and other expenses
 
13,289

 
11,050

 
38,383

 
44,534

 
 
 
 
 
 
 
 
 
Net Income
 
83,718

 
59,962

 
271,342

 
183,426

 
 
 
 
 
 
 
 
 
Other comprehensive income (loss):
 
 
 
 
 
 
 
 
Equity interest in unrealized gain (loss) on interest rate hedges (includes $83 and $68 for the three months ended and $244 and $145 for the nine months ended September 30, 2013 and September 30, 2012, respectively, of accumulated other comprehensive income reclassification for realized losses on interest rate hedges)
 
(102
)
 
(283
)
 
404

 
(441
)
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
$
83,616

 
$
59,679

 
$
271,746

 
$
182,985


See accompanying notes.


3


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

 
 
September 30,
2013
 
December 31,
2012
ASSETS
 
 
 
 
 
 
 
 
 
Current Assets:
 
 
 
 
Cash
 
$
107

 
$
185

Receivables:
 
 
 
 
Affiliates
 
1,304

 
2,656

Advances to affiliate
 
470,953

 
312,165

Trade and other
 
124,327

 
125,775

Transportation and exchange gas receivables
 
4,902

 
2,876

Inventories
 
47,469

 
45,918

Regulatory assets
 
30,998

 
36,706

Other
 
16,215

 
14,342

Total current assets
 
696,275

 
540,623

 
 
 
 
 
Investments, at cost plus equity in undistributed earnings
 
53,666

 
55,603

 
 
 
 
 
Property, Plant and Equipment:
 
 
 
 
Natural gas transmission plant
 
8,775,468

 
8,506,189

Less-Accumulated depreciation and amortization
 
3,051,284

 
2,954,276

Total property, plant and equipment, net
 
5,724,184

 
5,551,913

 
 
 
 
 
Other Assets:
 
 
 
 
Regulatory assets
 
275,581

 
214,912

Other
 
51,684

 
47,764

Total other assets
 
327,265

 
262,676

 
 
 
 
 
Total assets
 
$
6,801,390

 
$
6,410,815


(continued)




See accompanying notes.

4


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

 
 
September 30,
2013
 
December 31,
2012
LIABILITIES AND OWNER’S EQUITY
 
 
 
 
 
 
 
 
 
Current Liabilities:
 
 
 
 
Payables:
 
 
 
 
Affiliates
 
$
27,417

 
$
32,006

Trade and other
 
123,931

 
119,307

Transportation and exchange gas payables
 
1,646

 
3,513

Reserve for rate refunds
 
68,407

 

Accrued liabilities
 
152,865

 
139,333

Total current liabilities
 
374,266

 
294,159

 
 
 
 
 
Long-Term Debt
 
1,428,422

 
1,428,323

 
 
 
 
 
Other Long-Term Liabilities:
 

 

Asset retirement obligations
 
237,373

 
253,398

Regulatory liabilities
 
256,458

 
232,888

Other
 
19,616

 
5,339

Total other long-term liabilities
 
513,447

 
491,625

 
 
 
 
 
Contingent Liabilities and Commitments (Note 2)
 

 

 
 
 
 
 
Owner’s Equity:
 

 

Member’s capital
 
2,196,213

 
1,993,412

Retained earnings
 
2,289,360

 
2,204,018

Accumulated other comprehensive loss
 
(318
)
 
(722
)
Total owner’s equity
 
4,485,255

 
4,196,708

 
 
 
 
 
Total liabilities and owner’s equity
 
$
6,801,390

 
$
6,410,815





See accompanying notes.


5


TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
 
 
Nine months ended September 30,
 
 
2013
 
2012
Cash flows from operating activities:
 
 
 
 
Net income
 
$
271,342

 
$
183,426

Adjustments to reconcile net income to net cash provided by (used in) operating activities:
 
 
 
 
Depreciation and amortization
 
197,112

 
199,451

Allowance for equity funds used during construction (equity AFUDC)
 
(10,959
)
 
(9,935
)
Changes in operating assets and liabilities:
 
 
 
 
Receivables — affiliates
 
1,352

 
3,370

   — trade and other
 
1,448

 
13,093

Transportation and exchange gas receivable
 
(2,026
)
 
1,022

Inventories
 
295

 
1,199

Payables — affiliates
 
(4,589
)
 
13,078

     — trade
 
(25,480
)
 
(14,067
)
Accrued liabilities
 
23,645

 
(1,930
)
Reserve for rate refunds
 
68,407

 

Asset retirement obligation removal costs
 
(24,619
)
 
(30,646
)
Other, net
 
66,741

 
25,722

Net cash provided by operating activities
 
562,669

 
383,783

 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
Additions to long-term debt
 

 
398,804

Retirement of long-term debt
 

 
(325,000
)
Debt issue costs
 

 
(4,304
)
Cash distributions to parent
 
(186,000
)
 
(196,259
)
Cash contributions from parent
 
203,000

 
117,000

Other, net
 
9,143

 
(4,507
)
Net cash provided by (used in) financing activities
 
26,143

 
(14,266
)
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
Property, plant and equipment additions, net of equity AFUDC*
 
(418,565
)
 
(326,998
)
Disposal of property, plant and equipment, net
 
(1,786
)
 
9,920

Advances to affiliate, net
 
(158,788
)
 
(64,186
)
Return of capital from unconsolidated affiliates
 
916

 
11,327

Contributions to unconsolidated affiliates
 

 
(5,806
)
Purchase of ARO Trust investments
 
(44,975
)
 
(27,134
)
Proceeds from sale of ARO Trust investments
 
32,968

 
32,471

Other, net
 
1,340

 
825

Net cash used in investing activities
 
(588,890
)
 
(369,581
)
 
 
 
 
 
Increase (decrease) in cash
 
(78
)
 
(64
)
Cash at beginning of period
 
185

 
164

Cash at end of period
 
$
107

 
$
100

 
 
 
 
 
*       Increase to property, plant and equipment
 
$
(446,092
)
 
$
(327,634
)
Changes in related accounts payable and accrued liabilities
 
27,527

 
636

Property, plant and equipment additions, net of equity AFUDC
 
$
(418,565
)
 
$
(326,998
)
See accompanying notes.

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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 September 30, 2013, Williams holds an approximate 64 percent interest in WPZ, comprised of an approximate 62 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 September 30, 2013 and December 31, 2012 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $6.6 million and $13.3 million in the nine months ended September 30, 2013 and September 30, 2012, respectively. We made capital contributions to Cardinal related to Cardinal’s expansion project totaling $5.8 million in the nine months ended September 30, 2012. There were no contributions to Cardinal for the nine months ended September 30, 2013.
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 2012 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 increased Operation and maintenance costs $1.5 million and $5.4 million for the three and nine months ended September 30, 2012, respectively, for the reclassification from Taxes — other than income, with no net impact on Total operating costs and expenses, Operating Income or Net Income.
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

7


and other third-party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, 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 September 30, 2013, we had accrued approximately $68.4 million for amounts that are probable of being refunded or credited.
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 that would resolve all issues in this proceeding without the need for a hearing. The stipulation and agreement is subject to review and approval by the FERC.  We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required.
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). If the D.C. Circuit were to overturn the FERC’s order, 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 $5 million to $7 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 September 30, 2013, we had a balance of approximately $4.0 million for the expense portion of these estimated costs recorded in current liabilities ($2.8 million) and other long-term liabilities ($1.2 million) in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2012, we had a balance of approximately $3.3 million for the expense portion of these estimated costs recorded in current liabilities ($1.1 million) and other long-term liabilities ($2.2 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

8


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 $5 million to $7 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 $5 million to $7 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.
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 environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration was 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 was 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.
Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. The remaining emission control additions required to comply with the hazardous air pollutant regulations are estimated to include capital costs of $1 million through 2013, the compliance date.
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. We had a current regulatory asset of $0.7 million at September 30, 2013 for such deferred costs. We had no uncollected environmental related regulatory assets at December 31, 2012.
By letter dated September 20, 2007, the EPA required us to provide information regarding natural gas compressor 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

9


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.
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. DEBT AND FINANCING ARRANGEMENTS.
Credit Facility.
On July 31, 2013, WPZ amended the $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. The amended credit facility may also, under certain conditions, be increased up to an additional $500 million. Total letter of credit capacity available to WPZ under the credit facility is $1.3 billion. At September 30, 2013, no letters of credit have been issued and no loans are outstanding under our credit facility. We may borrow up to $500 million under the amended credit facility to the extent not otherwise utilized by WPZ and Northwest Pipeline LLC. At September 30, 2013, the full $500 million under the credit facility was available to us.
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. At September 30, 2013, WPZ had $371 million in outstanding commercial paper.
4. INVESTMENTS.
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, the revenues specifically designated for ARO. We established the ARO trust account (ARO Trust) on June 30, 2008. The ARO Trust carries a moderate risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.
Effective March 1, 2013, based on the Docket No. RP12-993 rate filing, the annual funding obligation increased to approximately $50.4 million, with installments paid monthly. This amount is subject to change pursuant to the final resolution of the rate case.

10


Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions):
 
 
September 30, 2013
 
December 31, 2012
 
Amortized
Cost Basis
 
Fair
Value
 
Amortized
Cost Basis
 
Fair
Value
Cash and Money Market Funds
$
6.3

 
$
6.3

 
$
1.3

 
$
1.3

U.S. Equity Funds
8.1

 
10.1

 
5.4

 
7.4

International Equity Funds
4.2

 
4.7

 
3.4

 
3.8

Municipal Bond Funds
9.7

 
9.8

 
4.9

 
5.3

Total
$
28.3

 
$
30.9

 
$
15.0

 
$
17.8


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 September 30, 2013:
 
 
 
 
 
 
 
 
 
 
Measured on a recurring basis:
 
 
 
 
 
 
 
 
 
 
ARO Trust investments
 
$
30.9

 
$
30.9

 
$
30.9

 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
Additional disclosures:
 
 
 
 
 
 
 
 
 
 
Notes receivable
 
6.9

 
6.9

 

 
6.9

 

Long-term debt
 
(1,428.4
)
 
(1,530.9
)
 

 
(1,530.9
)
 

 
 
 
 
 
 
 
 
 
 
 
Assets (liabilities) at December 31, 2012:
 
 
 
 
 
 
 
 
 
 
Measured on a recurring basis:
 
 
 
 
 
 
 
 
 
 
ARO Trust investments
 
$
17.8

 
$
17.8

 
$
17.8

 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
Additional disclosures:
 
 
 
 
 
 
 
 
 
 
Notes receivable
 
8.2

 
8.2

 

 
8.2

 

Long-term debt, including current portion
 
(1,428.3
)
 
(1,704.5
)
 

 
(1,704.5
)
 

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:
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 Docket No. RP06-569 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.

11


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 nine months ended September 30, 2013 or 2012.
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 September 30, 2013 and December 31, 2012, our advances to WPZ totaled approximately $471.0 million and $312.2 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 September 30, 2013, 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 $1.6 million and $14.1 million for the three and nine months ended September 30, 2013, respectively, and $7.5 million and $8.6 million for the three and nine months ended September 30, 2012, 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 $1.7 million and $5.7 million, for the three and nine months ended September 30, 2013, respectively, and $0.8 million and $3.2 million for the three and nine months ended September 30, 2012, 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 $79.5 million and $233.0 million in the three and nine months ended September 30, 2013, respectively, and $81.2 million and $238.7 million in the three and nine months ended September 30, 2012, 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.
Pursuant to an operating agreement, we serve as the contract operator on certain Williams Field Services Company (WFS) facilities. We recorded reductions in operating expenses for services provided to and reimbursed by WFS of $0.6 million and $1.7 million for the three and nine months ended September 30, 2013, respectively, and $1.1 million and $2.7 million for the three and nine months ended September 30, 2012, respectively, under terms of the operating agreement.
We made equity distributions to WPO totaling $186.0 million and $196.3 million during the nine months ended September 30, 2013 and 2012, respectively. During October 2013, we made an additional distribution to WPO of $64.0 million. In the nine months ended September 30, 2013 and 2012, respectively, WPO made contributions to us totaling

12


$203.0 million and $117.0 million to fund a portion of our expenditures for additions to property, plant and equipment. In October 2013, WPO made an additional $61.0 million contribution to us.
7. OTHER ACCRUALS.
Eminence Storage Field Abandonment — Due to the abandonment and retirement of four of the seven caverns at our Eminence Storage Field in 2013 and the expected recovery of such costs in our rates, we have reclassified $92 million of costs related to the Eminence ARO from Total property, plant and equipment, net to Regulatory assets (Eminence abandonment regulatory asset). Included in Other (income) expense, net, for the three and nine months ended September 30, 2013, consistent with the pending stipulation and agreement filed in our Docket No. RP12-993 general rate case proceeding, is a charge of $8.1 million and $14.5 million, respectively, related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates. We have also recognized income for the three and nine months ended September 30, 2013 of $3.3 million and $15.4 million, respectively, related to insurance recoveries associated with this event.

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 2012 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 nine months ended September 30, 2013 was $309.7 million compared to $228.0 million for the nine months ended September 30, 2012. Net income for the nine months ended September 30, 2013 was $271.3 million compared to $183.4 million for the nine months ended September 30, 2012. The increase in Operating income of $81.7 million (35.8 percent) was primarily due to higher Natural gas transportation revenues in the first nine months of 2013 compared to the same period in 2012 and a decrease in Operating Costs and Expenses, as discussed below. The increase in Net income of $87.9 million (47.9 percent) was mostly attributable to the increase in Operating income and by a favorable change in net expenses in Other (Income) and Other Expenses, as discussed below.
Sales Revenues.
Operating revenues: Natural gas sales increased $51.2 million (139.5 percent) for the nine months ended September 30, 2013 compared to the same period in 2012. 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 nine months ended September 30, 2013 increased $46.3 million (6.1 percent) over the same period in 2012. 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 positive variance were higher transportation reservation revenues related to new incremental projects of $40.3 million, ($27.4 million from our Mid-South project Phase 1 placed in service in September 2012 and Phase 2 placed in service in June 2013, $9.9 million from our Mid-Atlantic Connector project placed in service in January 2013 and $3.0 million from our Northeast Supply Link project placed in partial service in third quarter 2013), partially offset by $4.6 million lower recovery of electric power costs, $3.1 million lower transportation revenues due to a firm contract termination on the Mobile Bay lateral, and $2.2 million lower revenues due to one less billable day, as of result of leap year in 2012. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations.
Operating Costs and Expenses.
Excluding the Cost of natural gas sales, which is directly offset in revenues, of $87.9 million for the nine months ended September 30, 2013 and $36.7 million for the comparable period in 2012, our operating costs and expenses for the nine months ended September 30, 2013 decreased approximately $33.3 million (5.2 percent) from the comparable period in 2012. This decrease was primarily attributable to:
A $6.4 million (20.5 percent) favorable change in Other (income) expense, net primarily due to a $15.4 million gain recognized in 2013 related to insurance recoveries, offset by $14.5 million of expense in 2013 related to a charge for the regulatory asset that will not be recovered in rates, both associated with Eminence abandonment discussed below. Also contributing to the change was a decrease of $15.9 million of project feasibility costs, partially offset by a $9.8 million increase due to the amortization of regulatory assets resulting from ARO costs incurred prior to the Docket No. RP12-993 rate case;

13


A $25.5 million (11.6 percent) decrease in Operation and maintenance costs primarily resulting from a $10.2 million decrease in employee labor and related costs and a $15.3 million decrease primarily related to compressor and pipeline operation, maintenance and repairs;
A $5.2 million (19.0 percent) decrease in Cost of natural gas transportation primarily resulting from lower electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations.
Partially offset by a $4.6 million (3.5 percent) increase in Administrative and general costs primarily resulting from employee labor and related benefit costs.
Other (Income) and Other Expenses.
Other (income) and other expenses for the nine months ended September 30, 2013 had a favorable change of $6.1 million (13.7 percent) over the same period in 2012 primarily due to $5.8 million in lower interest expense due to the July 2012 refinancing of debt at lower interest rates.
Filing of Rate Case.
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 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 that would resolve all issues in this proceeding without the need for a hearing. The stipulation and agreement is subject to review and approval by the FERC.  We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required.
Eminence Storage Field Leak.
On December 28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Covington County, Mississippi. We initially reduced the pressure in the cavern by safely venting and flaring gas, and began the process of flowing all remaining gas into our pipeline. Due to the leak at this cavern and damage to the well at an adjacent cavern, both caverns were taken out of service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, experienced operating problems, and we determined that they should be retired. The event did not affect the performance of our obligations under our service agreements with our customers.
In September 2011 we filed an application with the FERC seeking authorization to abandon these four caverns. In February 2013, the FERC issued an order approving the abandonment. We estimate the cost to abandon the caverns, which will be capital in nature, will be approximately $103 million, which is expected to be spent through the first half of 2014. This estimate is subject to change as work progresses and additional information becomes known.
As of September 30, 2013, we have incurred approximately $91.6 million of these abandonment costs. Management considers these costs to be prudent costs incurred in the abandonment of these caverns. Consistent with the terms of the pending stipulation and agreement in the Docket No. RP12-993 rate case, for the three and nine months ended September 30, 2013, we expensed $8.1 million and $14.5 million, respectively, related to the Eminence abandonment regulatory asset that will not be recovered in rates.
We have reached settlement agreements with certain insurance counterparties related to this event. A portion of the proceeds from these settlements will be credited to the Eminence regulatory asset pursuant to the terms of the pending stipulation and agreement in the Docket No. RP12-993 rate case. The remaining balance of the proceeds are allocated to us to offset the expense associated with the write off of the uncollectible portion of the Eminence regulatory asset and a portion of our costs incurred to ensure the safety of the surrounding area. For the three and nine months

14


ended September 30, 2013, we have recognized $3.3 million and $15.4 million, respectively, related to these insurance recoveries.
During the three and nine months ended September 30, 2013, we incurred $1.0 million and $2.0 million, respectively, of expense, related primarily to costs to ensure the safety of the surrounding area. We anticipate incurring additional expense of approximately $4 million through the first half of 2014.
Capital Expenditures.
Our capital expenditures for the nine months ended September 30, 2013 were $418.6 million, compared to $327.0 million for the nine months ended September 30, 2012. The $91.6 million increase is primarily due to higher spending on expansion projects in 2013. Our capital expenditures estimate for 2013 and future capital projects are discussed in our 2012 Annual Report Form 10-K. The following describes those projects and certain new capital projects proposed by us.
Mid-South
The Mid-South Project involves an expansion of our mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. In August 2011, we received approval from the FERC for the project. The capital cost of the project is estimated to be approximately $200 million. We placed the first phase of the project into service in September 2012 which increased capacity by 95 Mdth/d. We placed the second phase of the project into service in June 2013 which increased capacity by an additional 130 Mdth/d.
Mid-Atlantic Connector
The Mid-Atlantic Connector Project involves an expansion of our mainline from an existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as Maryland. In July 2011, we received approval from the FERC for the project. The capital cost of the project is estimated to be approximately $60 million. We placed the project into service in the first quarter of 2013, and it increased capacity by 142 Mdth/d.
Northeast Supply Link
The Northeast Supply Link Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in Zone 6. In November 2012, we received approval from the FERC for the project. The capital cost of the project is estimated to be approximately $390 million. We placed a portion of the project into service in the third quarter 2013 increasing capacity by 125 Mdth/d. We plan to place the remaining portion into service in November 2013, and it will increase capacity by an additional 125 Mdth/d.
Rockaway Delivery Lateral
The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. We filed an application with the FERC in January 2013 for approval of the project. The capital cost of the project is estimated to be approximately $230 million. We plan to place the project into service during the second half of 2014, and the capacity of the lateral will 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. The capital cost of the project is estimated to be approximately $50 million. We plan to place the project into service during the second half of 2014, and it will increase capacity by 100 Mdth/d.
Virginia Southside
The Virginia Southside Project involves an expansion of our existing natural gas transmission system from the Zone 6 Station 210 Pooling Point in New Jersey to Dominion Virginia Power’s proposed power station in Brunswick

15


County, Virginia, and both our Cascade Creek interconnect with East Tennessee Natural Gas and our Pleasant Hill delivery point to Piedmont Natural Gas Company, Inc. in North Carolina. We filed an application with the FERC in December 2012 for approval of the project. The capital cost of the project is estimated to be approximately $300 million. We plan to place the project into service in September 2015, and it will 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. The capital cost of the project is estimated to be approximately $600 million. We plan to place the project into service in December 2015, and it will increase capacity by 525 Mdth/d.
Mobile Bay South III
The Mobile Bay South III Project involves an expansion of the Mobile Bay line south from Station 85 in west central Alabama to delivery points along the line. We filed an application with the FERC in July 2013 for approval of the project. The capital cost of the project is estimated to be approximately $50 million. We plan to place the project into service in April 2015, and it will increase capacity on the line by 225 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 near Rock Springs, Maryland. We plan to file an application with the FERC in the second quarter of 2014 for approval of the project. The capital cost of the project is estimated to be approximately $80 million. We plan to place the project into service in April 2016, and it will increase capacity by 192 Mdth/d.








16


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.
Third Quarter 2013 Changes in Internal Controls
There have been no changes during the third quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our Internal Controls.

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.


17


ITEM 6.
Exhibits.
The following instruments are included as exhibits to this report.
 
Exhibit
Number
 
Description
 
 
 
2.1
 
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 report Form 10-Q and incorporated herein by reference).
 
 
 
10
 
First Amended & Restated Credit Agreement, dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10 to Williams Partners L.P.’s Quarterly Report on 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.

 


18



SIGNATURE
Pursuant to the requirements of the Securities Exchange Act 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
(Registrant)
 
 
 
 
 
Dated:
October 31, 2013
By:
 
/s/ Jeffrey P. Heinrichs
 
 
 
 
Jeffrey P. Heinrichs
 
 
 
 
Controller
(Principal Accounting Officer)




EXHIBIT INDEX.

Exhibit
Number
 
Description
 
 
 
2.1
 
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 report Form 10-Q and incorporated herein by reference).
 
 
 
10
 
First Amended & Restated Credit Agreement, dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10 to Williams Partners L.P.’s Quarterly Report on 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.