UNITED STATES SECURITIES AND EXCHANGE COMMISSION


Washington, D.C. 20549




________________






Form 10-Q





(Mark One)





R
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended June 30, 2010OR£
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OFTHE SECURITIES EXCHANGE ACT OF 1934For the transition period from                                                      to





Commission File Number 1-2745







________________




Southern Natural Gas Company


(Exact Name of Registrant as Specified in Its Charter)





Delaware
63-0196650(State or Other Jurisdiction
(I.R.S. Employerof Incorporation or Organization)
Identification No.)El Paso Building1001 Louisiana StreetHouston, Texas
77002(Address of Principal Executive Offices)
(Zip Code)





Telephone Number: (713) 420-2600





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 R   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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes £  No £





Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or 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.





Large accelerated filer £Accelerated filer £Non-accelerated filer RSmaller 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 R











SOUTHERN NATURAL GAS COMPANY





TABLE OF CONTENTS





Caption
PagePART I — Financial InformationItem  1.
Financial Statements
1Item  2.
Management’s Discussion and Analysis of Financial Condition and  Results of Operations
9Item  3.
Quantitative and Qualitative Disclosures About Market  Risk
15Item  4.
Controls and Procedures
15PART II — Other InformationItem  1.
Legal Proceedings
16Item  1A.
Risk Factors
16Item  2.
Unregistered Sales of Equity Securities and Use of Proceeds
16Item  3.
Defaults Upon Senior Securities
16Item  4.
(Removed and Reserved)
16Item  5.
Other Information
16Item  6.
Exhibits
17Signatures
18








Below is a list of terms that are common to our industry and used throughout this document:/d
= per day
LNG
= liquefied natural gasBBtu
= billion British thermal units




When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.


When we refer to “us,” “we,” “our,” “ours,” or “the company,” we are describing Southern Natural Gas Company and/or our subsidiaries.








































i
 
 Table of Contents







PART I — FINANCIAL INFORMATION





Item 1. Financial Statements





SOUTHERN NATURAL GAS COMPANY





CONDENSED CONSOLIDATED STATEMENTS OF INCOME


(In millions)


(Unaudited)





Quarter Ended

June 30,


Six Months Ended

June 30,2010


2009


2010


2009Operating revenues

$
131


$
119


$
276


$
245Operating expensesOperation and maintenance


38



41



75



82Depreciation and amortization


14



13



29



27Taxes, other than income taxes


7



8



14



1559



62



118



124Operating income


72



57



158



121Earnings from unconsolidated affiliate


3



2



7



5Other income, net


1



5



2



1Interest and debt expense


(16
)


(16
)


(32
)


(32
)Affiliated interest income


—



—



1



1Net income

$
60


$
48


$
136


$
96





See accompanying notes.









































1
 Table of Contents







SOUTHERN NATURAL GAS COMPANY





CONDENSED CONSOLIDATED BALANCE SHEETS


(In millions)


(Unaudited)





June 30,

2010


December 31,

2009ASSETSCurrent assetsCash and cash equivalents

$
3


$
—Accounts and notes receivableCustomer


—



7Affiliates


85



64Other


19



2Materials and supplies


15



15Other


11



9Total current assets


133



97Property, plant and equipment, at cost


3,751



3,709Less accumulated depreciation and amortization


1,386



1,411Total property, plant and equipment, net


2,365



2,298Other assetsInvestment in unconsolidated affiliate


79



79Note receivable from affiliate


—



112Other


77



73156



264Total assets

$
2,654


$
2,659LIABILITIES AND PARTNERS’ CAPITALCurrent liabilitiesAccounts payableTrade

$
15


$
19Affiliates


22



27Other


26



16Taxes payable


13



9Accrued interest


18



18Asset retirement obligation


15



14Other


8



5Total current liabilities


117



108Long-term debt


910



910Other liabilities


28



27Commitments and contingencies (Note 4)Partners’ capital


1,599



1,614Total liabilities and partners’ capital

$
2,654


$
2,659





See accompanying notes.















2
 Table of Contents







SOUTHERN NATURAL GAS COMPANY





CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


(In millions)


(Unaudited)





Six Months Ended

June 30,2010


2009Cash flows from operating activitiesNet income

$
136


$
96Adjustments to reconcile net income to net cash from operating activitiesDepreciation and amortization


29



27Earnings from unconsolidated affiliate, adjusted for cash distributions


—



2Other non-cash income items


—



(1
)Asset and liability changes


(21
)


(8
)Net cash provided by operating activities


144



116Cash flows from investing activitiesCapital expenditures


(51
)


(93
)Net change in notes receivable from affiliate


69



61Acquisition


(18
)


—Proceeds from sale of asset


8



—Other


2



—Net cash provided by (used in) investing activities


10



(32
)Cash flows from financing activitiesDistributions to partners


(151
)


(84
)Net cash used in financing activities


(151
)


(84
)Net change in cash and cash equivalents


3



—Cash and cash equivalentsBeginning of period


—



—End of period

$
3


$
—





See accompanying notes.



































3
 Table of Contents







SOUTHERN NATURAL GAS COMPANY





NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


(Unaudited)





1. Basis of Presentation and Significant Accounting Policies





Basis of Presentation





We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. generally accepted accounting principles. You should read this report along with our 2009 Annual Report on Form 10-K, which contains a summary of our significant accounting policies and other disclosures. The financial statements as of June 30, 2010, and for the quarters and six months ended June 30, 2010 and 2009, are unaudited. We derived the condensed consolidated balance sheet as of December 31, 2009, from the audited balance sheet filed in our 2009 Annual Report on Form 10-K. In our opinion, we have made adjustments, all of which are of a normal, recurring nature to fairly present our interim period results. Due to the seasonal nature of our business, information for interim periods may not be indicative of our operating results for the entire year.





In June 2010, El Paso Pipeline Partners, L.P. (EPB) acquired an additional 20 percent ownership interest in us from El Paso Corporation (El Paso).  The acquisition increased EPB’s interest in us to 45 percent with El Paso retaining the remaining 55 percent.




Significant Accounting Policies





The following is an update of our significant accounting policies and accounting pronouncements issued but not yet adopted as discussed in our 2009 Annual Report on Form 10-K.





Transfers of Financial Assets.On January 1, 2010, we adopted an accounting standards update for financial asset transfers.  Among other items, this update requires the sale of an entire financial asset or a proportionate interest in a financial asset in order to qualify for sale accounting.  These changes were effective for sales of financial assets occurring on or after January 1, 2010.  In January 2010, we terminated our prior accounts receivable sales program under which we previously sold a senior interest in certain accounts receivable  to a third party financial institution (through a wholly-owned special purpose entity).  As a result, the adoption of this accounting standards update did not have a material impact on our financial statements.  Upon termination of the prior accounts receivable sales program, we entered into a new accounts receivable sales program under which we sell certain accounts receivable in their entirety to the third party financial institution (through a wholly-owned special purpose entity).  The transfer of these receivables qualifies for sale accounting under the provisions of this accounting standards update.  We present the cash flows related to the prior and new accounts receivable sales programs as operating cash flows in our statements of cash flows.  For further information, see Note 5.





Variable Interest Entities.On January 1, 2010, we adopted an accounting standards update for variable interest entities that revise how companies determine the primary beneficiary of these entities, among other changes. Companies are now required to use a qualitative approach based on their responsibilities and power over the entities’ operations, rather than a quantitative approach in determining the primary beneficiary as previously required. The adoption of this accounting standards update did not have a material impact on our financial statements.





2. Acquisition / Divestiture





During the first quarter of 2010, we purchased certain pipeline assets from Elba Express Company, L.L.C. (Elba Express), our affiliate, for $18 million and sold certain pipeline assets to Elba Express for net proceeds of $8 million. We recorded both the purchase and sale at their historical cost and accordingly, we recognized no gain or loss on these transactions.















4
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3. Fair Value of Financial Instruments





At June 30, 2010 and December 31, 2009, the carrying amounts of cash and cash equivalents and accounts receivable and payable are representative of their fair value because of the short-term nature of these instruments. At June 30, 2010 and December 31, 2009, we had an interest bearing note receivable from El Paso of approximately $85 million and $154 million due upon demand, with a variable interest rate of 1.6% and 1.5% . While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates its carrying value due to the note being due on demand and the market-based nature of the interest rate.





In addition, the carrying amounts of our long-term debt and their estimated fair values, which are based on quoted market prices for the same or similar issues, are as follows:





June 30, 2010


December 31, 2009Carrying

Amount


Fair

Value


Carrying

Amount


Fair

Value(In millions)Long-term debt, including current maturities

$
910


$
984


$
910


$
977





4. Commitments and Contingencies





Legal Proceedings





We and our affiliates are named defendants in numerous lawsuits and governmental proceedings and claims that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. At June 30, 2010, we accrued approximately $2 million for our outstanding legal matters.





Environmental Matters





We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect  of the disposal or release of specified substances at current and former operating sites. At June 30, 2010 and December 31, 2009, we have accrued less than $1 million for expected remediation costs and associated onsite, offsite and groundwater technical studies.





Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.





Superfund Matters. Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated as a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as Superfund, or state equivalents for one active site. Liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. We consider the financial strength of other PRPs in estimating our liabilities.





We expect to make capital expenditures for environmental matters of less than $1 million in the aggregate for the remainder of 2010 through 2014.





It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.


5
 Table of Contents


Rates and Regulatory Matters




Rate Case.In January 2010, the Federal Energy Regulatory Commission (FERC) approved our settlement in which we (i) increased our base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file our next general rate case to be effective after August 31, 2012, but no later than September 1, 2013, and (iv) extended the vast majority of our firm transportation contracts until August 31, 2013.





Guarantees





We are or have been involved in various ownership and other contractual arrangements that sometimes require us to provide additional financial support that results in the issuance of performance guarantees that are not recorded in our financial statements. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. As of June 30, 2010, we have a performance guarantee related to contracts held by Southern LNG, Inc., an entity formerly owned by us, with a maximum exposure of $225 million. We estimate our potential exposure related to this guarantee is approximately $5 million, which is based on the remaining estimated obligations under the contracts.





5. Accounts Receivable Sales Program





During 2009, we had an agreement to sell a senior interest in certain accounts receivable (which are short-term assets that generally settle within 60 days) to a third party financial institution (through a wholly-owned special purpose entity), and we retained subordinated interest in those receivables.The sale of the senior interest qualified for sale accounting and was conducted to accelerate cash from these receivables, the proceeds from which were used to increase liquidity and lower our overall cost of capital.  During the quarter and six months ended June 30, 2009, we received $65 million and $134 million of cash related to the sale of the senior interest, collected $62 million and $135 million from the subordinated interest we retained in the receivables, and recognized a loss of less than $1 million on these transactions.  At December 31, 2009, the third party financial institution held $30 million of senior interest and we held $19 million of subordinated interest.  Our subordinated interest is reflected in accounts receivable on our balance sheet.  In January 2010, we terminated this accounts receivable sales program and paid $30 million to acquire the senior interest. We reflected the cash flows related to the accounts receivable sold under this program, changes in our retained subordinated interest, and cash paid to terminate the program, as operating cash flows on our statement of cash flows.





In the first quarter of 2010, we entered into a new accounts receivable sales program to continue to sell accounts receivable to the third party financial institution that qualify for sale accounting under the updated accounting standards related to financial asset transfers.  Under this program, we sell  receivables in their entirety to the third party financial institution (through a wholly-owned special purpose entity).  As of June 30, 2010, the third party financial institution held $47 million of the accounts receivable we sold under the program. In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables.  Our ability to recover this additional amount is based solely on the collection of the underlying receivables.  During the  quarter and six months ended June 30, 2010, we received $88 million and $211 million of cash up front from the sale of the receivables and received an additional $52 million and $109 million of cash upon the collection of the underlying receivables.  As of June 30, 2010, we had not collected approximately $16 million related to our accounts receivable sales, which is reflected as other accounts receivable on our balance sheet.  We recognized a loss of less than $1 million on our accounts receivable sales during the quarter and six months ended June 30, 2010.  Because the cash received up front and the cash received as the underlying receivables are collected both are related to the sale or ultimate collection of the underlying receivables, and not subject to significant other risks given their short term nature, we reflect all cash flows under the new accounts receivable sales program as operating cash flows on our statement of cash flows.















6
 Table of Contents


Under both the prior and current accounts receivable sales programs, we serviced the underlying receivables for a fee. The fair value of these servicing agreements as well as the fees earned were not material to our financial statements for the periods ended June 30, 2010 and 2009.





The third party financial institution involved in both of these accounts receivable sales programs acquires interests in various financial assets and issues commercial paper to fund those acquisitions.  We do not consolidate the third party financial institution because we do not have the power to direct its overall activities (and do not absorb a majority of its expected losses) since our receivables do not comprise a significant portion of its operations.





6. Investment in Unconsolidated Affiliate and Transactions with Affiliates





Investment in Unconsolidated Affiliate





We have a 50 percent ownership interest in Bear Creek Storage Company, L.L.C. (Bear Creek), a joint venture with Tennessee Gas Pipeline Company, our affiliate. For the six months ended June 30, 2010 and 2009 we received $7 million in cash dividends from Bear Creek.  In July 2010, we received an additional $4 million in cash dividends.  Also, in July 2010, Bear Creek utilized its note receivable balance under the cash management program with El Paso to pay a  cash distribution to its partners, including $23 million to us.





Summarized financial information of our proportionate share of our unconsolidated affiliate for the periods ended June 30 is presented as follows:


Quarter Ended

June 30,


Six Months Ended

June 30,2010


2009


2010


2009(In millions)Operating results data:Operating revenues

$
5


$
4


$
10


$
9Operating expenses


2



2



3



4Income from continuing operations and net income


3



2



7



5





Transactions with Affiliates





EPB Acquisition.  In June 2010, EPB acquired an additional 20 percent ownership interest in us from El Paso.  The acquisition increased EPB’s interest in us to 45 percent with El Paso retaining the remaining 55 percent.


Distributions.We are required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. During the six months ended June 30, 2010 and 2009, we paid cash distributions of approximately $151 million and $84 million to our partners. In addition, in July 2010, we paid a cash distribution to our partners of approximately $54 million.





Cash Management Program.We participate in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At June 30, 2010 and December 31, 2009, we had a note receivable from El Paso of $85 million and $154 million. We classified $85 million of this receivable as current on our balance sheet at June 30, 2010, based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. The interest rate on this variable rate note was 1.6% and 1.5% at June 30, 2010 and December 31, 2009.



















7
 Table of Contents











Affiliate Revenues and Expenses. We enter into transactions with our affiliates within the ordinary course of business.  For a further discussion of our affiliated transactions, see our 2009 Annual Report on Form 10-K. The following table shows revenues and charges from our affiliates for the quarters and six months ended June 30:





Quarter Ended

June 30,


Six Months Ended

June 30,2010


2009


2010


2009(In millions)Revenues from affiliates

$
2


$
2


$
4


$
3Operation and maintenance expenses from affiliates


29



31



59



62Reimbursement of operating expenses charged to affiliates


1



4



2



8

























































8
 Table of Contents





Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations





The information contained in Item 2 updates, and should be read in conjunction with, the information disclosed in our 2009 Annual Report on Form 10-K, and the financial statements and notes presented in Item 1 of this Quarterly Report on Form 10-Q.





Results of Operations





Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business, which consists of consolidated operations as well as an investment in an unconsolidated affiliate. We believe EBIT is useful to investors to provide them with the same measure used by El Paso to evaluate our performance. We define EBIT as net income adjusted for items such as    (i) interest and debt expense and (ii) affiliated interest income. We exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT to our net income, our throughput volumes and an analysis and discussion of our results for the quarter and six months ended June 30, 2010, compared with the same periods in 2009.





Operating Results:


Quarter Ended

June 30,


Six Months Ended

June 30,2010


2009


2010


2009(In millions, except for volumes)Operating revenues

$
131


$
119


$
276


$
245Operating expenses


(59
)


(62
)


(118
)


(124
)Operating income


72



57



158



121Earnings from unconsolidated affiliate


3



2



7



5Other income, net


1



5



2



1EBIT


76



64



167



127Interest and debt expense


(16
)


(16
)


(32
)


(32
)Affiliated interest income


—



—



1



1Net income

$
60


$
48


$
136


$
96Throughput volumes (BBtu/d)(1)


2,175



2,204



2,535



2,374


_________


(1) Throughput volumes include billable transportation throughput volumes for storage injection.





EBIT Analysis:


Quarter Ended June 30, 2010


Six Months Ended June 30, 2010Operating

Revenue


Operating

Expense


Other


Total


Operating

Revenue


Operating

Expense


Other


TotalFavorable/(Unfavorable)

(In millions)Reservation and other services revenues

$
14


$
—


$
—


$
14


$
32


$
—


$
—


$
32Gas not used in operations and other natural gas sales and purchases


(3
)


3



—



—



(2
)


9



—



7Other(1)


1



—



(3
)


(2
)


1



(3
)


3



1Total impact on EBIT

$
12


$
3


$
(3
)

$
12


$
31


$
6


$
3


$
40


_________


(1)Consists of individually insignificant items.





Reservation and Other Services Revenues. During the quarter and six months ended June 30, 2010, our reservation and other services revenues increased primarily due to higher tariff rates placed into service on September 1, 2009 pursuant to our rate case settlement discussed below, and higher throughput volumes due to colder weather during the winter months.




9
 Table of Contents


In January 2010, the FERC approved our rate case settlement in which we (i) increased our base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file our next general rate case to be effective after August 31, 2012 but no later than September 1, 2013, and (iv) extended the vast majority of our firm transportation contracts until August 31, 2013.





Gas Not Used in Operations and Other Natural Gas Sales and Purchases.  Prior to September 1, 2009, the financial impacts of our operational gas, net of gas used in operations, were based on the price of natural gas and the amount of natural gas we were allowed to retain and dispose of according to our tariff, relative to the amounts of natural gas we used for operating purposes and the cost of operating our electric compression facilities.  Effective September 1, 2009, a volume tracker was implemented as part of our rate case settlement and therefore we no longer share retained gas not used in operations.  For the six months ended June 30, 2010, our EBIT was favorably impacted by $7 million as compared to the same period in 2009 due to electric compression costs being recorded to the volume tracker  in 2010 versus  being expensed in 2009 as part of our  rate case settlement, and favorably impacted by $4 million due to higher cost associated with replacement of depleted storage volumes during the first quarter of 2009. This was partially offset by a $4 million unfavorable impact due to the elimination of our fuel sharing mechanism as part of our rate case settlement. For a further discussion of gas not used in operation and other natural gas sales and purchases, see our 2009 Annual Report on Form 10-K.





Affiliated Interest Income





The following table shows the average advances due from El Paso and the average short-term interest rates for the quarters and six months ended June 30:





Quarter Ended

June 30,


Six Months Ended

June 30,2010


2009


2010


2009(In millions)Average advance due from El Paso

$
97


$
83


$
117


$
93Average short-term interest rate


1.5
%


1.7
%


1.5
%


2.0
%























































10
 Table of Contents







Liquidity and Capital Resources





Our primary sources of liquidity are cash flows from operating activities, amounts available under El Paso’s cash management program and capital contributions from our partners. At June 30, 2010, we had a note receivable from El Paso of approximately $85 million which was classified as current based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. See Item 1, Financial Statements, Note 6, for a further discussion of El Paso’s cash management program.  Our primary uses of cash are for working capital, capital expenditures and required distributions to our partners.





Although financial market conditions have improved since late 2008 and early 2009, volatility in the remainder of 2010 and beyond in the financial markets could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Additionally, although the impacts are difficult to quantify at this point, a prolonged recovery of the global economy could have adverse impacts on natural gas consumption and demand.  However, we believe our exposure to changes in natural gas consumption and demand is largely mitigated by a revenue base that is significantly comprised of long-term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas.





We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flows from operating activities, amounts available to us under El Paso’s cash management program and capital contributions from our partners. As of June 30, 2010, El Paso had approximately $2.9 billion of available liquidity, including approximately $2.2 billion of capacity available to it under various committed credit facilities. While we do not anticipate a need to directly access the financial markets in the remainder of 2010 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions may impact our ability to act opportunistically.





2010 Cash Flow Activities. Our cash flows for the six months ended June 30, 2010 are summarized as follows (in millions):


Cash Flow from OperationsNet income

$
136Non-cash income adjustments


29Change in assets and liabilities


(21
)Total cash flow from operations


144Cash InflowsInvesting activitiesProceeds from sale of asset


8Net change in notes receivable from affiliate


69Other


2Total other cash inflows


79Cash OutflowsInvesting activitiesCapital Expenditures


51Acquisition


1869Financing activitiesDistributions to partners


151Total cash outflows


220Net change in cash

$
3













11
 Table of Contents









During the six months ended June 30, 2010, we generated $144 million of operating cash flows. We utilized these amounts and our note receivable under El Paso’s cash management program to fund maintenance of our system as well as pay distributions to our partners. During the six months  ended June 30, 2010, we paid cash distributions of approximately $151 million to our partners. In addition, in July 2010, we paid a cash distribution to our partners of approximately $54 million. Our cash capital expenditures for the six months ended June 30, 2010 and our estimated capital expenditures for the remainder of this year to expand and maintain our system are listed below:





Six Months Ended

June 30, 2010


2010

Remaining


Total(In millions)Maintenance

$
13


$
73


$
86Expansion


38



148



186$
51


$
221


$
272

































































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Commitments and Contingencies





Below is a summary of certain climate change and energy policies recently enacted or proposed that, if enacted, will likely impact our business. For a further discussion of our commitments and contingencies, see Item 1, Financial Statements, Note 4 which is incorporated herein by reference.





Climate Change Legislation and Regulation. Legislative and regulatory efforts to address climate change and greenhouse gas (GHG) emissions are in various phases of discussions or implementation at international, federal, regional and state levels. We believe that legislation that either limits or sets a price on carbon emissions will increase demand for natural gas depending on the legislative provisions ultimately adopted. However, we also believe it is reasonably likely that the federal legislation being contemplated, as well as recently adopted and proposed federal regulations, would increase our cost of environmental compliance by requiring us to purchase emission allowances or offset credits, install additional equipment or change work practices, and could materially increase the cost of goods and services we purchase from suppliers due to their increased compliance costs. Although we believe that many of these costs should be recoverable in our rates, recovery through these mechanisms is still uncertain at this time.





The Environmental Protection Agency (EPA) has adopted regulations that require us to monitor and report certain GHG emissions from our operations on an annual basis. The EPA has proposed to further expand the monitoring and reporting requirements to additional natural gas transmission sources which could materially increase the costs of our operations. Our preliminary estimate of the first-year cost to our company is $1 million.





The EPA has also adopted regulations that will require permits to be obtained under the Clean Air Act for GHG emissions above certain thresholds. Depending on the thresholds ultimately established by the EPA, these permit requirements could have a material impact upon the costs of our operations, could require us to install new equipment to control emissions from our facilities, and could result in delays and negative impacts on our ability to obtain permits and other regulatory approvals with regard to new and existing facilities. The EPA’s regulations are being challenged in the federal courts; however, pending such judicial reviews, the thresholds that have been established by the EPA through at least 2016 are not expected to have a material impact on our operations or financial results.





It is uncertain what federal or state legislation or regulations will ultimately be adopted and whether adopted regulations will withstand likely legal challenges. Therefore, the potential impact on our operations and construction projects remains uncertain.





Energy Legislation.In conjunction with these climate change proposals, there have been various federal and state legislative and regulatory proposals that would create additional incentives to move to a less carbon intensive “footprint”. Although it is reasonably likely that many of these proposals will be enacted over the next few years, we cannot predict the form of any laws and regulations that might be enacted, the timing of their implementation, or the precise impact on our operations or demand for natural gas. However, such proposals if enacted could impact natural gas demand over the longer term.





Air Quality Regulations. In March 2009, the EPA proposed a rule that is expected to be finalized later in 2010 impacting emissions of hazardous air pollutants from reciprocating internal combustion engines and requiring us to install emission controls on our pipeline system. As proposed, engines subject to the regulations would have to be in compliance by August 2013. Based upon that timeframe, we expect that we would begin incurring expenditures in late 2010, incur the majority of the expenditures in 2011 and 2012, and expend any remaining amounts in early 2013. Based on our expectation that the final rule will be similar to a recently adopted rule applicable to diesel engines, our current estimated impact is approximately $5 million in capital expenditures over the period from 2010 to 2013.























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In February 2010, the EPA promulgated a new one-hour National Ambient Air Quality Standard (NAAQS) for oxides of nitrogen (NO2).  The new standard is in addition to the existing annual NAAQS which was not changed.  While it is uncertain how the EPA and the states will apply the new one-hour NAAQS, the new NAAQS may impact our ability to obtain permits and other regulatory approvals with regard to existing and new facilities and may cause us to incur costs to install additional controls on existing and new facilities.  The EPA’s new rule is being challenged in the federal courts.  While the new NAAQS, if upheld, could have a material impact on our cost of operations and our cost to install new facilities, we are unable, at this point, to estimate its financial impact.



























































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Item 3. Quantitative and Qualitative Disclosures About Market Risk





There are no material changes in our quantitative and qualitative disclosures about market risks from those reported in our 2009 Annual Report on Form 10-K.





Item 4. Controls and Procedures





Evaluation of Disclosure Controls and Procedures





As of June 30, 2010, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our President and CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect 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 our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objective and our President and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a – 15(e) and 15d – 15(e)) were effective as of June 30, 2010.





Changes in Internal Control Over Financial Reporting





There were no changes in our internal control over financial reporting during the second quarter of 2010 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.





































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PART II — OTHER INFORMATION





Item 1. Legal Proceedings





See Part I, Item 1, Financial Statements, Note 4 which is incorporated herein by reference.





Item 1A. Risk Factors





CAUTIONARY STATEMENTS FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF


THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995





This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and differences between assumed facts and actual results can be material, depending upon the circumstances. Where, based on assumptions, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur, be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.





Important factors that could cause actual results to differ materially from estimates or projections contained in forward-looking statements are described in our 2009 Annual Report on Form 10-K under Part I, Item 1A, Risk Factors. There have been no material changes in these risk factors since that report.





Item 2. Unregistered Sales of Equity Securities and Use of Proceeds





None.





Item 3. Defaults Upon Senior Securities





None.





Item 4. (Removed and Reserved)





Item 5. Other Information





None.



























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Item 6. Exhibits





The Exhibit Index is hereby incorporated herein by reference.


The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:





·
should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;


·
may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;


·
may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and


·
were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.





Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.


















































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SIGNATURES





Pursuant to the requirements of the Securities Exchange Act of 1934, Southern Natural Gas Company has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.








SOUTHERN NATURAL GAS COMPANYDate: August 6, 2010
/s/ Norman G. HolmesNorman G. Holmes

President

(Principal Executive Officer)Date: August 6, 2010
/s/ John R. SultJohn R. Sult

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)


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SOUTHERN NATURAL GAS COMPANY





EXHIBIT INDEX





Each exhibit identified below is filed as a part of this report.





Exhibit

Number
Description3.A
Second Amendment to General Partnership Agreement of Southern Natural Gas Company.3.B
Third Amendment to General Partnership Agreement of Southern Natural Gas Company.31.A
Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.B
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32.A
Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32.B
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

















































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