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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, 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  (Do not check if a smaller reporting company)		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.

 

 

 

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TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC

Index

 

Part I. Financial Information:			Page
Item 1. Financial Statements
Condensed Consolidated Statement of Comprehensive Income —Three Ended March 31, 2013 and 2012			3
Condensed Consolidated Balance Sheet — March 31, 2013 and December 31, 2012			4
Condensed Consolidated Statement of Cash Flows — Three Months Ended March 31, 2013 and 2012			6
Notes to Condensed Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			13
Item 4. Controls and Procedures			16
Part II. Other Information			16
Item 1. Legal Proceedings			16
Item 6. Exhibits			17

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;

 

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Business strategy;

 

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Cash flow from operations or results of operations;

 

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Rate case filings;

 

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Natural gas prices, supply and demand; and

 

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Demand for our services.

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

 

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Availability of supplies, market demand, and volatility of prices;

 

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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;

 

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Development of alternative energy sources;

 

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The impact of operational and development hazards and unforeseen interruptions;

 

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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;

 

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Changes in maintenance and construction costs;

 

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Changes in the current geopolitical situation;

 

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Our exposure to the credit risks of our customers and counterparties;

 

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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;

 

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Risks associated with weather and natural phenomena including climate conditions;

 

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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.

 

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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,
		2013				2012
Operating Revenues:
Natural gas sales		$	24,571			$	10,146
Natural gas transportation			269,577				262,467
Natural gas storage			35,590				35,750
Other			1,324				1,516
Total operating revenues			331,062				309,879
Operating Costs and Expenses:
Cost of natural gas sales			24,571				10,146
Cost of natural gas transportation			10,854				11,383
Operation and maintenance			60,454				63,606
Administrative and general			47,023				46,070
Depreciation and amortization			76,693				65,995
Taxes — other than income taxes			11,626				11,440
Other (income) expense, net			(1,920	)			7,781
Total operating costs and expenses			229,301				216,421
Operating Income			101,761				93,458
Other (Income) and Other Expenses:
Interest expense			20,554				23,718
Allowance for equity and borrowed funds used during construction (AFUDC)			(4,830	)			(3,511	)
Equity in earnings of unconsolidated affiliates			(1,258	)			(1,536	)
Miscellaneous other (income) expenses, net			(1,680	)			4
Total other (income) and other expenses			12,786				18,675
Net Income			88,975				74,783
Other comprehensive income (loss):
Equity interest in unrealized gain (loss) on interest rate hedges (includes $79 for 2013 and $37 for 2012 of accumulated other comprehensive income reclassification for realized losses on interest rate hedges)			102				(25	)
Comprehensive Income		$	89,077			$	74,758

See accompanying notes.

 

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)

 

		March 31, 2013				December 31, 2012
ASSETS
Current Assets:
Cash		$	139			$	185
Receivables:
Affiliates			2,924				2,656
Advances to affiliate			385,343				312,165
Trade and other			131,891				125,775
Transportation and exchange gas receivables			4,748				2,876
Inventories			51,960				45,918
Regulatory assets			47,261				36,706
Other			7,323				14,342
Total current assets			631,589				540,623
Investments, at cost plus equity in undistributed earnings			54,767				55,603
Property, Plant and Equipment:
Natural gas transmission plant			8,573,438				8,506,189
Less-Accumulated depreciation and amortization			2,974,574				2,954,276
Total property, plant and equipment, net			5,598,864				5,551,913
Other Assets:
Regulatory assets			206,690				214,912
Other			45,279				47,764
Total other assets			251,969				262,676
Total assets		$	6,537,189			$	6,410,815

(continued)

See accompanying notes.

 

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

(Unaudited)

 

		March 31, 2013				December 31, 2012
LIABILITIES AND OWNER’S EQUITY
Current Liabilities:
Payables:
Affiliates		$	26,533			$	32,006
Trade and other			135,785				119,307
Transportation and exchange gas payables			2,948				3,513
Accrued liabilities			171,248				139,333
Total current liabilities			336,514				294,159
Long-Term Debt			1,428,356				1,428,323
Other Long-Term Liabilities:
Asset retirement obligations			253,766				253,398
Regulatory liabilities			237,718				232,888
Other			5,049				5,339
Total other long-term liabilities			496,533				491,625
Contingent Liabilities and Commitments (Note 2)
Owner’s Equity:
Member’s capital			2,048,412				1,993,412
Retained earnings			2,227,994				2,204,018
Accumulated other comprehensive loss			(620	)			(722	)
Total owner’s equity			4,275,786				4,196,708
Total liabilities and owner’s equity		$	6,537,189			$	6,410,815

See accompanying notes.

 

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

(Unaudited)

 

		Three months ended March 31,
		2013				2012
Cash flows from operating activities:
Net income		$	88,975			$	74,783
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization			76,466				66,102
Allowance for equity funds used during construction (equity AFUDC)			(3,366	)			(2,414	)
Changes in operating assets and liabilities:
Receivables — affiliates			(268	)			5,156
— others			(6,116	)			(3,529	)
Transportation and exchange gas receivable			(1,872	)			2,539
Inventories			(4,196	)			(892	)
Payables — affiliates			(5,473	)			14,502
— others			(9,242	)			(24,137	)
Accrued liabilities			11,735				(7,866	)
Reserve for rate refunds			10,574				—
Asset retirement obligation removal costs			(1,847	)			(7,873	)
Other, net			4,641				9,131
Net cash provided by operating activities			160,011				125,502
Cash flows from financing activities:
Cash distributions to parent			(65,000	)			(54,259	)
Cash contributions from parent			55,000				34,000
Other, net			7,542				(5,931	)
Net cash used in financing activities			(2,458	)			(26,190	)
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*			(85,816	)			(61,611	)
Disposal of property, plant and equipment, net			1,423				3,438
Advances to affiliate, net			(73,178	)			(39,755	)
Contributions to unconsolidated affiliates			—				(3,998	)
Purchase of ARO Trust investments			(8,938	)			(7,766	)
Proceeds from sale of ARO Trust investments			8,577				10,305
Other, net			333				13
Net cash used in investing activities			(157,599	)			(99,374	)
Decrease in cash			(46	)			(62	)
Cash at beginning of period			185				164
Cash at end of period		$	139			$	102
*    Increase to property, plant and equipment		$	(109,985	)		$	(80,361	)
Changes in related accounts payable and accrued liabilities			24,169				18,750
Property, plant and equipment additions, net of equity AFUDC		$	(85,816	)		$	(61,611	)

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 March 31, 2013, Williams holds an approximate 68 percent interest in WPZ, comprised of an approximate 66 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, 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 $2.2 million and $1.0 million in the three months ended March 31, 2013 and March 31, 2012, respectively. We made capital contributions to Cardinal related to Cardinal’s expansion project totaling $4.0 million in the three months ended March 31, 2012. There were no contributions to Cardinal for the three months ended 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 $4.3 million for the reclassifications of $2.1 million from Administrative and general and $2.2 million 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.

 

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As a result of the ratemaking process, certain revenues collected by us may be subject to refund upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and estimated total exposure, as 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 March 31, 2013, we had accrued approximately $10.6 million for potential amounts to be 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 and suspending our filing to be effective March 1, 2013, subject to refund and the outcome of a hearing, except that rates for certain services that were proposed as overall rate decreases were accepted, without suspension, to be effective October 1, 2012. These decreased rates will not be subject to refund, but may be subject to decrease prospectively under the Natural Gas Act of 1938, Section 5. The increased rates became effective March 1, 2013, subject to refund and the outcome of a hearing. 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 March 31, 2013, we had a balance of approximately $3.1 million for the expense portion of these estimated costs recorded in current liabilities ($1.1 million) and other long-term liabilities ($2.0 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.

 

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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 $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 in the range of $10 million to $12 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. This standard is subject to challenges in federal court. 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. However, we had no uncollected environmental related regulatory assets at March 31, 2013 or December 31, 2012.

 

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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.

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.

Commitments.

We have commitments for construction and acquisition of property, plant and equipment of approximately $316 million at March 31, 2013.

3. DEBT AND FINANCING ARRANGEMENTS.

Credit Facility.

Total letter of credit capacity available to WPZ under the $2.4 billion credit facility is $1.3 billion. At March 31, 2013, WPZ had a total of $250 million in loans outstanding under the credit facility and no letters of credit have been issued. We may borrow up to $400 million under the credit facility to the extent not otherwise utilized by WPZ and Northwest Pipeline GP. At March 31, 2013, the full $400 million under the credit facility was available to us.

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 RP12-993 rate filing, the annual funding obligation increased to approximately $50.4 million, with installments paid monthly.

 

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Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions):

 

		March, 31, 2013								December 31, 2012
		Amortized Cost Basis				Fair Value				Amortized Cost Basis				Fair Value
Money Market Funds		$	4.4			$	4.4			$	1.3			$	1.3
U.S. Equity Funds			4.0				5.7				5.4				7.4
International Equity Funds			2.0				2.3				3.4				3.8
Municipal Bond Funds			6.2				6.5				4.9				5.3
Total		$	16.6			$	18.9			$	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 March 31, 2013:
Measured on a recurring basis:
ARO Trust investments		$	18.9			$	18.9			$	18.9			$	—			$	—
Additional disclosures:
Notes receivable			7.9				7.9				—				7.9				—
Long-term debt			(1,428.4	)			(1,671.1	)			—				(1,671.1	)			—
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 our 2008 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

 

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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, 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 March 31, 2013 and December 31, 2012, our advances to WPZ totaled approximately $385.3 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 March 31, 2013, the interest rate was 0.01 percent.

Included in our operating revenues for the three months ending March 31, 2013 and 2012 are revenues received from affiliates of $5.9 million and $0.2 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in our cost of sales for the three months ended March 31, 2013 and 2012 is the cost of gas purchased from affiliates of $2.4 million and $1.3 million, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams for all direct and indirect expenses it incurs or payments it makes (including salary, bonus, incentive compensation and benefits) in connection with these services. We were billed $45.9 million and $51.0 million in the three months ended March 31, 2013 and 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.

Employees of Williams also provide general and administrative 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. Our share of direct and allocated administrative expenses is reflected in Administrative and general expenses in the Condensed Consolidated Statement of Comprehensive Income. 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. Included in our Administrative and general expenses for the three months ended March 31, 2013 and 2012, were $16.8 million and $15.8 million, respectively, for management services charged by Williams and other affiliated companies.

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 $0.5 million and $0.7 million for the three months ended March 31, 2013 and 2012, respectively, under terms of the operating agreement.

 

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We made equity distributions to WPO totaling $65.0 million and $54.3 million during the three months ended March 31, 2013 and 2012, respectively. During April 2013, we made an additional distribution to WPO of $58.0 million. In the three months ended March 31, 2013 and 2012, respectively, WPO made contributions totaling $55.0 million and $34.0 million to us to fund a portion of our expenditures for additions to property, plant and equipment. In April 2013, WPO made an additional $52.0 million contribution to us.

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 three months ended March 31, 2013 was $101.8 million compared to $93.5 million for the three months ended March 31, 2012. Net income for the three months ended March 31, 2013 was $89.0 million compared to $74.8 million for the three months ended March 31, 2012. The increase in Operating income of $8.3 million (8.9 percent) was primarily due to higher Natural gas transportation revenues in the first three 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 $14.2 million (19.0 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.

Transportation Revenues.

Operating revenues: Natural gas transportation for the three months ended March 31, 2013 increased $7.1 million (2.7 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 of $11.0 million, ($8.1 million from our Mid-South project placed in service in September 2012 and $2.9 million from our Mid-Atlantic Connector project placed in service in January 2013), partially offset by $2.2 million lower revenues due to one less billable day, as of result of leap year in 2012, and $0.8 million lower electric power costs in 2013. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations.

Sales Revenues.

Operating revenues: Natural gas sales increased $14.5 million (143.6 percent) for the three months ended March 31, 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.

Operating Costs and Expenses.

Excluding the Cost of natural gas sales, which is directly offset in revenues, of $24.6 million for the three months ended March 31, 2013 and $10.1 million for the comparable period in 2012, our operating costs and expenses for the three months ended March 31, 2013 decreased approximately $1.6 million (0.8 percent) from the comparable period in 2012. This decrease was primarily attributable to:

 

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•

A $9.7 million favorable change in Other (income) expense, net primarily due to a $7.2 million increase in regulatory credits to defer ARO costs related to increased depreciation expense associated with the Eminence abandonment discussed below. Also contributing to the change was a decrease of $6.0 million of project feasibility costs, partially offset by a $2.7 million accrual for a certain litigation matter;

 

•

A $3.1 million (4.9 percent) decrease in Operation and maintenance costs primarily resulting from a $2.4 million decrease in employee labor and related costs;

 

•

Partially offset by a $10.7 million (16.2 percent) increase in Depreciation and amortization costs primarily resulting from an increase in depreciation of the Eminence ARO asset over the remaining life of caverns one through four as approved by the FERC in the related abandonment filing.

Other (Income) and Other Expenses.

Other (income) and other expenses for the three months ended March 31, 2013 had a favorable change of $5.9 million (31.6 percent) over the same period in 2012 primarily due to a $3.1 million in lower interest expense due to the July 2012 refinancing of debt at lower interest rates, $1.7 million higher amount of reimbursements for tax gross-up related to reimbursable projects, and a $1.3 million increase in AFUDC.

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 have reduced the pressure in the cavern by safely venting and flaring gas, and by flowing gas into our pipeline. Due to the leak at this cavern and damage to the well at an adjacent cavern, both caverns are out of service. The event has not affected the performance of our obligations under our service agreements with our customers.

As a result of these occurrences, we have determined that these two caverns cannot be returned to service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should be retired. 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 $93 million, which is expected to be spent through the end of 2013. This estimate is subject to change as work progresses and additional information becomes known. To the extent available, the abandonment costs will be funded from the ARO Trust. As of March 31, 2013, we have incurred approximately $71 million of abandonment costs. Management considers these costs to be prudent costs incurred in the abandonment of these caverns and expects to recover these costs, net of any insurance proceeds, in future rate filings.

During the three months ended March 31, 2013, we incurred $0.5 million, 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 remainder of 2013.

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 and suspending our filing to be effective March 1, 2013, subject to refund and the outcome of a hearing, except that rates for certain services that were proposed as overall rate decreases were accepted, without suspension, to be effective October 1, 2012. These decreased rates will not be subject to refund, but may be subject to decrease prospectively under the Natural Gas Act of 1938, Section 5. The increased rates became effective March 1, 2013, subject to refund and the outcome of a hearing. We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required.

 

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Capital Expenditures.

Our capital expenditures for the three months ended March 31, 2013 were $85.8 million, compared to $61.6 million for the three months ended March 31, 2012. The $24.2 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 Expansion 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 plan to place the second phase of the project into service in June 2013 which will increase 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 plan to place the project into service in November 2013, and it will increase capacity by 250 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. The capital cost of the project is estimated to be approximately $180 million. We plan to place the project into service during the second half of 2014, and its capacity 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. 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 Expansion 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 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.

 

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Leidy Southeast

The Leidy Southeast Expansion 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 point in Alabama. We anticipate filing an application with the FERC in the fourth quarter of 2013. 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 469 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 anticipate filing an application with the FERC in the second quarter of 2013. 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.

 

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) 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 make modifications as necessary; our intent in this regard is that the Disclosure 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.

First Quarter 2013 Changes in Internal Controls

There have been no changes during the first quarter of 2013 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.

 

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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).
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.

 

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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 8, 2013		By: /s/ Jeffrey P. Heinrichs
		Jeffrey P. Heinrichs
		Controller
		(Principal Accounting Officer)

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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).
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.