-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, OFEEH+N+YyTgSgq+yzTqpC70vk1Lf/tqsI+p38oKbzc0/mGtyRP1BoavvrehL+07 oRQBXvFPHbDsv1qO9lfXTA== 0001336047-09-000012.txt : 20090420 0001336047-09-000012.hdr.sgml : 20090420 20090224162843 ACCESSION NUMBER: 0001336047-09-000012 CONFORMED SUBMISSION TYPE: CORRESP PUBLIC DOCUMENT COUNT: 3 FILED AS OF DATE: 20090224 FILER: COMPANY DATA: COMPANY CONFORMED NAME: Boardwalk Pipeline Partners, LP CENTRAL INDEX KEY: 0001336047 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 203265614 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: CORRESP BUSINESS ADDRESS: STREET 1: 3800 FREDERICA STREET CITY: OWENSBORO STATE: KY ZIP: 42301 BUSINESS PHONE: 270-926-8686 MAIL ADDRESS: STREET 1: 3800 FREDERICA STREET CITY: OWENSBORO STATE: KY ZIP: 42301 CORRESP 1 filename1.htm secresponse02242009.htm

 
 
 


 








February 24, 2009

United States Securities and Exchange Commission
Division of Corporation Finance
100 F Street, NE
Washington, D.C.  20549
Attn: H. Christopher Owings
    
 Re:    
Boardwalk Pipeline Partners, LP
Comment Letter dated February 18, 2009
Form 10-K for the fiscal year ended December 31, 2007, filed February 26, 2008, and
 
Forms 10-Q for the fiscal quarters ended March 31, 2008, June 30, 2008 and September 30, 2008, filed April 29, 2008, July 29, 2008 and October 28, 2008
File No. 001-32665


VIA EDGAR FILING AND FACSIMILE TRANSMISSION – 202-772-9202


Dear Mr. Owings:

This letter sets forth the responses of Boardwalk Pipeline Partners, LP, a Delaware limited partnership, (the “Company” or the “Registrant”), to the comments received from the staff (the “Staff”) of the Division of Corporation Finance of the Securities and Exchange Commission (the “Commission”) by the letter (the “Comment Letter”) dated February 18, 2009, concerning the Company’s Form 10-K for the fiscal year ended December 31, 2007 (the “Form 10-K”) and Forms 10-Q for the fiscal quarters ended March 31, 2008, June 30, 2008 and September 30, 2008 (File No. 001-32665) (collectively, the “Reports”).

The Registrant filed its Annual Report on Form 10-K for the year ended December 31, 2008, with the Commission on February 24, 2009, (the 2008 Form 10-K).  In response to the Staff’s comments numbered 2, 3 and 4, the Registrant has provided herein excerpts from its 2008 Form 10-K.  However, we refer the Staff to the full text of the 2008 Form 10-K, particularly the Items noted in this response, for a more complete discussion of the matters addressed therein.
 
The numbers of the responses in this letter correspond to the numbers of the Staff’s comments as set forth in the Comment Letter.  References in the text of the responses herein to captions and page numbers are to the captions and pages numbers in the respective Reports.  Capitalized terms used in this letter and not otherwise defined herein have the meanings given to them in the respective Reports.



 
                                        
 

9 Greenway Plaza,  Suite 2800  Houston, Texas  77046  713.479.8000
 
 
 
 


Mr. H. Christopher Owings
United States Securities and Exchange Commission
February 24, 2009
Page 2 of 12



Form 10-K for the Fiscal Year Ended December 31, 2007
 
Item 1. Business, page 3
 
Introduction, page 3
 
  1.  
We note your response to comment one in our letter dated December 23, 2008.  Please disclose your total partnership interests so that we can understand how you calculated Loews Corporation’s 68.0% total partnership interest.  Also, please disclose your calculation of Loews Corporations’ 70.38% total partnership interest including how general partnership interests convert into limited partner units for purposes of calculating total equity ownership.  Please discuss how Loews Corporation’s indirect ownership of the Registrant’s incentive distribution rights affects Loews Corporation’s total equity ownership interest, if at all, and why you did not include these interests in your calculation of their total equity ownership.
 
Response:

The following table shows the calculation of the equity ownership percentages discussed in the Registrant’s response dated January 16, 2009, to comment one of the December 23, 2008, Comment Letter.
   
Units Outstanding
at
December 31, 2007
        
Limited Partner Units:
            
Common units owned by Loews
     53,256,122        
Subordinated units owned by Loews
     33,093,878        
Subtotal of units owned by Loews
     86,350,000      
A
  
Common units owned by the public
     37,400,000          
Total Limited Partner Units (Representing 98% of the Registrant's Equity)
     123,750,000       B  
                 
Calculation of limited partner interest owned by Loews as a percentage
   of total limited partner interests (rounded)
     69.70 %     A / B  
Calculation of limited partner interest owned by Loews as a percentage
   of total equity interests
     68.38 %  (C)  
A / (B / 0.98)
Calculation of limited and general partner interests owned by Loews as
   a percentage of total equity interests
     70.38 %     C+ 0.02


The Registrant has included the following disclosure in Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, in its 2008 Form 10-K:

Our Partnership Interests

As of December 31, 2008, we had outstanding 154.9 million common units, 22.9 million class B units, a 2% general partner interest and incentive distribution rights (IDRs).  The common units and class B units together represent all of our limited partner interests and 98% of our total ownership interests, in each case excluding our IDRs. As discussed below under Our Cash Distribution Policy—Incentive Distribution Rights, the IDRs represent the right for the holder to receive varying percentages of quarterly distributions of available cash from operating surplus in excess of certain specified target quarterly distribution levels.  As such, the IDRs cannot be expressed as a constant percentage of our total ownership interests.

 
Mr. H. Christopher Owings
United States Securities and Exchange Commission
February 24, 2009
Page 3 of 12
 
BPHC, a wholly-owned subsidiary of Loews, owns 107.5 million of our common units, all 22.9 million of our class B units and, through Boardwalk GP, LP, an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of the IDRs.  The common units, class B units and general partner interest held by BPHC represent approximately 74% of our equity interests.  The additional interest represented by the IDRs is not included in such ownership percentage because, as noted above, the IDRs cannot be expressed as a constant percentage of our ownership.

Item 3.  Legal Proceedings, page 26
 
2.  
We note your responses to comment two in our letter dated December 23, 2008.  Please provide a sample of how you intend to comply with this comment in your future filings.
 
Response:  The Registrant has included the following disclosure in Note 3 to its Notes to Consolidated Financial Statements in Item 8 of its 2008 Form 10-K:

Napoleonville Salt Dome Matter

Following the December 2003 accidental release of natural gas from storage in a salt dome cavern operated by Gulf South at the Dow Hydrocarbon and Resources, Inc. (Dow Hydrocarbon), Grand Bayou facility in Belle Rose, Louisiana, several suits were filed, including two that were initially filed as class actions. One of the cases initially filed as a class action was settled in 2008.

A lawsuit entitled Crystal Aucoin, et al. v. Gulf South Pipeline Company, LP, et al., No. 28,157 was filed on February 12, 2004, in the 23rd Judicial District Court for the Parish of Assumption, State of Louisiana. The suit was initially filed as a class action. The defendants at the trial were Gulf South, Dow Chemical Company (Dow Chemical), Dow Hydrocarbon and one of Gulf South’s insurers, Oil Insurance Limited (OIL). The plaintiffs voluntarily dismissed their class action allegations on February 2, 2006. Since that time the case has proceeded in the same court as a mass joinder of approximately 1,200 individual claims. The plaintiffs seek damages for alleged inconvenience and emotional distress arising from being forced to drive on a detour around a road closed due to the gas release. A trial was held in August 2008 on damages for a sample group of 23 plaintiffs. In January 2009, the court awarded damages to these plaintiffs of less than $0.1 million in the aggregate. Gulf South and the other defendants are considering whether to appeal the ruling. Pursuant to an agreement among defendants, Gulf South is responsible for one half of the judgment, subject to final determination of Gulf South’s claim for indemnification from Dow Chemical. Any judgment amounts paid would be covered by insurance.

On September 29, 2005, OIL filed suit against Dow Chemical and Dow Hydrocarbon, No. 29,217, in the 23rd Judicial District Court for the Parish of Assumption, State of Louisiana, Oil Insurance Limited v. Dow Chemical Company, et al. OIL seeks indemnification from Dow Hydrocarbon for amounts of insurance paid to Gulf South. Dow Hydrocarbon has filed a demand against OIL and a third-party claim against Gulf South. Dow Hydrocarbon’s allegations against Gulf South include contractual violations and liability due to negligence and strict liability. Dow Hydrocarbon seeks recovery for property damage, damages arising from the loss of use of certain wells/caverns and damages incurred responding to and remediating the natural gas leak. The case is ongoing and no trial date has been set.


 
 
Mr. H. Christopher Owings
United States Securities and Exchange Commission
February 24, 2009
Page 4 of 12
 
 
Item 7.  Management’s Discussion and Analysis of Financial Conditions and Results of Operations, page 31
 
  3.  
We note your response to comments three and 25 in our letter dated December 23, 2008.  Please provide a sample of how you intend to comply with these comments in your future filings.
 
Response: Set forth below are excerpts from Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, of the 2008 Form 10-K, which the Registrant believes are responsive to the Staff’s request.  However, we also refer the Staff to the full text of said Item 7:

Factors that Impact our Results of Operations

A significant portion of our operating revenues is derived from reservation charges under multi-year firm contracts, therefore the risk of revenue fluctuations due to near-term changes in natural gas supply and demand conditions, competition and price volatility is significantly mitigated. For the year ended December 31, 2008, 66% of our operating revenues were associated with reservation charges under firm contracts which do not vary based on capacity utilization. Excluding contracts associated with our expansion projects currently under construction, the weighted average contract life of our contracts is approximately 4.1 years. Regardless of these factors, our business can be impacted by shifts in supply and demand dynamics, the mix of services requested by customers and by competition and regulatory requirements, particularly when accompanied by downturns or sluggishness in the economy, especially over a longer term.

Changing Customer Mix and Credit Profile

After completion of our expansion projects, producers will comprise a larger portion of our revenues, both as a group and separately. We expect producers as a group to contribute a much more significant portion of our future revenues, and one producer to represent over 10% of our 2009 revenues. Historically producers have had lower credit ratings than marketing companies, which have typically accounted for a large portion of our revenues. Therefore the expected change in our customer base could result in higher total credit risk.

Current economic conditions also indicate that many of our customers may encounter increased credit risk in the near term. We actively monitor the credit status of our counterparties and to date have not had any significant credit defaults associated with our transactions. However, given the current volatility in the financial markets, we cannot be certain that we will not experience such losses in the future.  Item 1A, Risk Factors, of this Report contains more information regarding the risks related to our customer base.

Competition and Contract Renewals

We compete primarily with other interstate and intrastate pipelines in the transportation and storage of natural gas, particularly in the Midwest and Gulf Coast states where we compete with numerous existing pipelines and will compete with pipelines under construction such as the Rockies Express Pipeline and the Mid-Continent Express Pipeline. We compete for renewals of expiring transportation and storage contracts, as well as new transportation contracts that will support growth projects.

Despite these competitive conditions, substantially all of the operating capacity on our expansion projects is sold out and our legacy systems are supported by long-term contracts having an average remaining life of 4.1 years. However, as of December 31, 2008, approximately 17% of the firm contract load on our pipeline systems, excluding agreements related to the expansion projects not yet in service, was due to expire on or before December 31, 2009. In addition, approximately 55% of our long-term contracts with firm deliveries to Lebanon, Ohio, the northeastern terminus of our pipeline system, will expire or become terminable by the customer by the end of 2010. In 2008, we were successful in remarketing and renewing the approximately 25% of our firm contract load that was due to expire during that year, in many cases obtaining favorable rates and extended contract terms. Notwithstanding that success, however, the 2009 and 2010 contract expirations and termination rights create uncertainty as we cannot give assurances that we will successfully remarket this capacity. Our ability to remarket available capacity will be impacted by additional competition from newly constructed pipelines, fluctuating commodity prices, a recessionary economy which could impact demand for and supply of natural gas and numerous other factors beyond our control. Item 1A, Risk Factors, contains more information regarding the risks related to competition in our industry.

 
 
Mr. H. Christopher Owings
United States Securities and Exchange Commission
February 24, 2009
Page 5 of 12
 
 
Natural Gas Prices

High natural gas prices in recent years have driven increased production levels in producing locations such as the Bossier Sands and Barnett Shale gas producing regions in East Texas, which have resulted in widened basis differentials on our systems and have benefited our transportation revenues. The high natural gas prices have also driven increased production in regions such as the Fayetteville Shale in Arkansas and the Caney Woodford Shale in Oklahoma, which, together with the higher production levels in East Texas, have formed the basis for several pipeline expansion projects including those constructed and being undertaken by us.
 
The price for natural gas has declined since its peak in the late summer 2008, although average prices continue to remain at elevated levels from those seen historically. Many of our customers have been negatively impacted by these recent declines in natural gas prices as well as current conditions in the capital markets, which factors have caused several of our producer customers to announce plans to decrease drilling levels and, in some cases, to consider shutting in natural gas production from some producing wells, which could adversely affect the volumes of natural gas we transport. While the majority of our revenue is derived from capacity reservation charges that are not impacted by the volume of natural gas transported; a significant portion of our revenue, approximately 34% in 2008, is derived from charges based on actual volumes transported under firm and interruptible services. As a result, lower volumes of natural gas transported would result in lower revenues from natural gas transportation operations. Based on the significant level of revenue we receive from reservation capacity charges under long-term contracts and our review of the recent announcements of drilling plans by our customers, we do not expect the current level of natural gas prices to have a significant adverse effect on our operating results. However, we cannot give assurances that this will be the case, or that commodity prices will not decline further, which could result in a further reduction in drilling activities by our customers.
 
In addition, spreads in natural gas prices between time periods, such as winter to summer, impact our PAL and interruptible storage revenues. These period to period price spreads, which were favorable for our PAL and interruptible storage services during 2006 and early 2007, decreased substantially in 2007 and continued to decrease into 2008, which resulted in reduced PAL and interruptible storage revenues for those periods. We cannot predict future time period spreads or basis differentials.

Reduction of Operating Pressures on Expansion Pipelines; Applications for Special Permits from PHMSA

As discussed elsewhere in this report, we have discovered anomalies in a small number of pipe joints on our East Texas Pipeline. As a result, and as a prudent operator, we have elected to reduce operating pressures on that pipeline to 20% below its previous operating level, which was below the pipeline’s maximum non-special permit operating pressures. Operating at lower pressures reduces the amount of gas that can flow through a pipeline and therefore will reduce our expected revenues and cash flow. We do not expect to return to normal operating pressures, or to operate at higher pressures under the special permit discussed below, until after we have completed our investigation and remediation measures, as appropriate, and PHMSA has concurred with our determination to increase pressures. We will also incur costs to replace defective pipe segments on the East Texas Pipeline, some of which may be reimbursable from vendors, and expect to temporarily shut down that pipeline when performing the necessary remedial measures, up to and including replacing certain pipe segments. We will work with PHMSA to return the East Texas Pipeline to its previous status under the special permit after we have completed our investigation and remediation. We cannot determine at this time the amount of costs we will incur or when we might raise operating pressures.  We have not completed testing on all of our expansion pipelines and could find anomalies on other pipelines which could have similar impacts with respect to those pipelines.

 
 

Mr. H. Christopher Owings
United States Securities and Exchange Commission
February 24, 2009
Page 6 of 12
 
 
Our ability to transport a portion of the expected maximum capacity on each of our expansion project pipelines is contingent upon our receipt of authority to operate these pipelines at higher operating pressures under special permits issued by PHMSA. We have received authority to operate the East Texas Pipeline under a special permit and have received the special permits for our Southeast, Gulf Crossing and Fayetteville and Greenville Laterals, but we have not received authority to operate under these permits. PHMSA retains discretion as to whether to grant, or to maintain in force, authority to operate any of our pipelines at higher operating pressures. Absent such authority, we will not be able to transport all of the contracted for quantities of natural gas on these pipelines.  To the extent that PHMSA does not grant us authority to operate any of our expansion pipelines under a special permit or withdraws previously granted authority to operate under a special permit, transportation capacity made available to the market and our transportation revenues and cash flows would be reduced.

For additional information, see Item 1 – Business - Expansion Projects and Item 1A - Risk Factors – A portion of the expected maximum daily capacity of our pipeline expansion projects is subject to our obtaining and maintaining authority from PHMSA to operate under higher operating pressures.


Credit and Capital Markets Disruption
 
Current economic conditions have made it difficult for companies to obtain funding in either the debt or equity markets. The current constraints in the capital markets may affect our ability to obtain funding through new borrowings or the issuance of equity in the public markets. In addition, we expect that, to the extent we are successful in arranging new debt financing, we will incur increased costs associated with these debt financings. As of December 31, 2008, in addition to $312.7 million of cash on hand and short-term investments, we had available capacity under our credit facility of $161.5 million which we subsequently fully borrowed against. We expect to utilize these resources, along with cash from operations and proceeds from debt and equity offerings, to fund our growth capital expenditures and working capital needs during 2009. See Liquidity and Capital Resources – Expansion Capital Expenditures below for a discussion of our financing plans for our current expansion projects.


Liquidity and Capital Resources
 
We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include cash generated from operating activities, our revolving credit facility, debt issuances and sales of limited partner units. Our operating subsidiaries use funds from their respective operations to fund their operating activities and maintenance capital requirements, service their indebtedness and make advances or distributions to Boardwalk Pipelines. Boardwalk Pipelines uses cash provided from the operating subsidiaries and, as needed, borrowings under its revolving credit facility discussed below, to service its outstanding indebtedness and, when available, make distributions or advances to us to fund our distributions to unitholders. We have no material guarantees of debt or other similar commitments to unaffiliated parties.

Our operating subsidiaries participate in an intercompany cash management program to the extent they are permitted under FERC regulations. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, Boardwalk Pipelines either provides cash to them or they provide cash to Boardwalk Pipelines.

Beginning in 2007 and continuing in 2008, the capital markets have been impacted by macroeconomic, liquidity, credit and recessionary concerns. During this period, we have continued to have access to the majority of our credit facility to fund our short-term liquidity needs. In 2008, we issued common units and class B units and received additional contributions from our general partner. We also received net proceeds of $247.2 million from the issuance of long-term debt in March 2008. See discussion below under Equity and Debt Financing. Our ability to continue to access capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions. We anticipate that our existing capital resources, ability to obtain financing and cash flow generated from future operations will enable us to maintain our current level of operations and our planned operations, including capital expenditures, for 2009.

 
 

Mr. H. Christopher Owings
United States Securities and Exchange Commission
February 24, 2009
Page 7 of 12
 
 
Maintenance Capital Expenditures

Maintenance capital expenditures were $50.5 million, $47.1 million and $41.7 million in 2008, 2007 and 2006. We expect to fund our 2009 maintenance capital expenditures of approximately $67.8 million from our operating cash flows.

Expansion Capital Expenditures

We are currently engaged in several pipeline expansion projects, described in Item I, Our Business – Expansion Projects, of this Report and expect the estimated total cost of these projects to be as follows (in millions):

   
Estimated Total Cost
(1)
    
Cash Invested through
December 31,
2008
  
Southeast Expansion
   $ 775     $ 707.3  
Gulf Crossing Project
     1,800       1,403.5  
Fayetteville and Greenville Laterals
     1,290       684.2  
    Total
   $ 3,865     $ 2,795.0  

(1)  
Our cost estimates are based on internally developed financial models and timelines. Factors in the estimates include, but are not limited to, those related to pipeline costs based on mileage, size and type of pipe, materials and construction and engineering costs.

Based upon our current cost estimates, we expect to incur capital expenditures of approximately $1.0 billion in 2009 and 2010 to complete our pipeline expansion projects. The majority of the expenditures are expected to occur during the first half of 2009, with the remaining costs associated with the construction of additional compression facilities for the Gulf Crossing Project and the Fayetteville and Greenville Laterals to be incurred in the latter half of 2009 and into 2010.

We are also engaged in the Western Kentucky Storage Expansion project. The cost of this project is expected to be approximately $87.7 million. Through December 31, 2008, we spent $48.0 million related to this project.

Our cost and timing estimates for these projects are subject to a variety of risks and uncertainties, including obtaining regulatory approvals; adverse weather conditions; delays in obtaining key materials; shortages of qualified labor and escalating costs of labor and materials. As the announced expansion projects move toward completion, the risks and uncertainties associated with the expansion projects are decreasing. However, certain risks remain, primarily involving river crossings and receipt of regulatory authority to operate the pipelines at higher operating pressures.

We have financed our expansion capital costs through the issuance of equity and debt, including sales of debt by us and our subsidiaries, borrowings under our revolving credit facility and available operating cash flow in excess of our operating needs. We anticipate we will need to finance an additional $500.0 million to complete our expansion projects. Our largest unitholder, Loews, has advised us that it is willing to provide the capital we need to complete the expansion projects to the extent the public markets remain unavailable on acceptable terms. We have not committed to any transaction at this time, however, and any additional financing provided by Loews would be subject to review and approval, as to fairness, by our independent Conflicts Committee. Item 1A, Risk Factors, contains more information regarding risks associated with our expansion projects and the related financing.

 
 
Mr. H. Christopher Owings
United States Securities and Exchange Commission
February 24, 2009
Page 8 of 12
 
 
Equity and Debt Financing

In 2008, we received net cash proceeds of approximately $1.7 billion from the following equity and debt issuances which proceeds were used to fund a portion of the costs of our ongoing expansion projects and to repay amounts borrowed under our revolving credit facility (in millions, except issue price):

Month of Issuance
  
Net Cash Proceeds Received
  
Number of Units
  
Issue Price
  
Type of Issuance
October
  
$
500.0 (a)
  
21.2
  
$
23.13
  
Private placement of common units to BPHC
June
    
700.0 (b)
  
22.9
    
30.00
  
Private placement of class B units to BPHC
June
    
248.8 (c)
  
10.0
    
25.30
  
Public offering of common units
March
    
247.2
  
N/A
    
N/A
  
Public offering of debt securities

(a)  
Includes a $10.0 million contribution received from our general partner to maintain its 2% general partner interest.
(b)  
Includes a $14.0 million contribution received from our general partner to maintain its 2% general partner interest.
(c)  
Includes a $5.2 million contribution received from our general partner to maintain its 2% general partner interest.

We also borrowed under our revolving credit facility, to the extent necessary, to finance our expansion projects. As discussed in Expansion Capital Expenditures we have a committed sponsor in Loews who has agreed to finance up to the remaining amount necessary to complete our expansion projects to the extent that the capital markets are not available on acceptable terms.  We do not have an immediate need to refinance any of our long-term debt, including borrowings under our revolving credit facility, as the earliest maturity date of such indebtedness is in 2012. We believe that our cash flow from operations will be sufficient to support our ongoing operations and maintenance capital requirements.

Credit Facility

We maintain a revolving credit facility which has aggregate lending commitments of $1.0 billion, under which Boardwalk Pipelines, Gulf South and Texas Gas each may borrow funds, up to applicable sub-limits. A financial institution which has a $50.0 million commitment under the revolving credit facility filed for bankruptcy protection in the third quarter 2008 and has not funded its portion of our borrowing requests since that time. Interest on amounts drawn under the credit facility is payable at a floating rate equal to an applicable spread per annum over the London Interbank Offered Rate or a base rate defined as the greater of the prime rate or the Federal funds rate plus 50 basis points. The revolving credit facility has a maturity date of June 29, 2012.

As of December 31, 2008, we had $792.0 million of loans outstanding under the revolving credit facility with a weighted-average interest rate on the borrowings of 3.43% and had no letters of credit issued. We were in compliance with all covenant requirements under our credit facility at December 31, 2008.  Subsequent to December 31, 2008, we borrowed all of the remaining unfunded commitments under the credit facility (excluding the unfunded commitment of the bankrupt lender noted above) which increased borrowings to $953.5 million.

Our revolving credit facility contains customary negative covenants, including, among others, limitations on the payment of cash dividends and other restricted payments, the incurrence of additional debt, sale-leaseback transactions and transactions with our affiliates. The facility also contains a financial covenant that requires us and our subsidiaries to maintain a ratio of total consolidated debt to consolidated earnings before income taxes, depreciation and amortization (as defined in the credit agreement), measured for the preceding twelve months, of not more than five to one. Although we do not believe that these covenants have had, or will have, a material impact on our business and financing activities or our ability to obtain the financing to maintain operations and continue our capital investments, they could restrict us in some circumstances as stated in Item 1A, Risk Factors. In particular, maintaining compliance with the financial covenant may limit our ability to incur additional indebtedness to finance our growth projects, which could limit our growth opportunities or require the issuance of more equity securities by us than previously anticipated.

 
Mr. H. Christopher Owings
United States Securities and Exchange Commission
February 24, 2009
Page 9 of 12
 
Contractual Obligations
 
The following table summarizes significant contractual cash payment obligations under firm commitments as of December 31, 2008, by period (in millions):
   
Total
    
Less than 1 Year
    
1-3 Years
    
4-5 Years
    
More than 5 Years
  
Principal payments on long-term debt (1)
   $ 2,902.0       -       -     $ 1,267.0     $ 1,635.0  
Interest on long-term debt (2)
     921.9     $ 117.5     $ 234.9       214.4       355.1  
Capital commitments (3)
     198.7       195.8       2.9       -       -  
Pipeline capacity agreements (4)
     102.8       12.6       22.5       20.5       47.2  
Operating lease commitments
     25.7       3.3       6.2       6.0       10.2  
Total
   $ 4,151.1     $ 329.2     $ 266.5     $ 1,507.9     $ 2,047.5  

(1)  
This includes our senior unsecured notes, having maturity dates from 2012 to 2027 and $792.0 million of loans outstanding under our revolving credit facility, having a maturity date of June 29, 2012.

(2)  
Interest obligations represent interest due on our senior unsecured notes at fixed rates. Future interest obligations under our revolving credit facility are uncertain, due to the variable interest rate and fluctuating balances. Based on a 3.43% weighted-average interest rate on amounts outstanding under our revolving credit facility as of December 31, 2008, $27.2 million, $54.3 million and $13.6 million would be due under the credit facility in less than one year, 1-3 years, and 4-5 years.

(3)  
Capital commitments represent binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements existing at December 31, 2008. The amounts shown do not reflect commitments we have made after December 31, 2008. For information on these projects, please read Expansion Capital Expenditures.

(4)  
The amounts shown are associated with various pipeline capacity agreements on third-party pipelines that allow our operating subsidiaries to transport gas to off-system markets on behalf of our customers.

Pursuant to the settlement of the Texas Gas rate case in 2006, we are required to annually fund an amount to the Texas Gas pension plan equal to the amount of actuarially determined net periodic pension cost, including a minimum of $3.0 million. In 2009, we expect to fund approximately $5.0 million to the Texas Gas pension plan.
 


Item 7A.  Quantitative and Qualitative Disclosures about Market Risk, page 41

4.  
We note your response to comment 8 in our letter dated December 23, 2008.  Please provide a sample of how you intend to comply with this comment in your future filings.
 
 
  Response:
 
The Registrant has included the following disclosure in Item 7A, Quantitative and Qualitative Disclosures about Market Risk of its 2008 Form 10-K:
 
 
 
Mr. H. Christopher Owings
United States Securities and Exchange Commission
February 24, 2009
Page 10 of 12
 
 
Item 7A.  Quantitative and Qualitative Disclosures About Market Risk
 

Interest rate risk:

With the exception of our revolving credit facility, for which the interest rate is reset each quarter, our debt has been issued at fixed rates. For fixed rate debt, changes in interest rates affect the fair value of the debt instruments but do not directly affect earnings or cash flows. The following table presents market risk associated with our fixed-rate long-term debt at December 31 (in millions, except interest rates):

   
2008
    
2007
  
Carrying value of debt
   $ 2,097.4     $ 1,847.9  
Fair value of debt
   $ 1,863.3     $ 1,834.2  
100 basis point increase in interest rates and resulting debt decrease
   $ 117.1     $ 118.8  
100 basis point decrease in interest rates and resulting debt increase
   $ 126.1     $ 129.3  
Weighted-average interest rate
     5.89 %     5.82 %

At December 31, 2008, we had $792.0 million outstanding under our revolving credit agreement at a weighted- average interest rate of 3.43%, which rate is reset each quarter. A 1% increase or decrease in interest rates would increase or reduce our cash payments for interest on the credit facility by $8.0 million on an annual basis. No amounts were borrowed under our revolving credit facility at December 31, 2007.

At December 31, 2008, $137.7 million of our undistributed cash, shown on the balance sheets as Cash and cash equivalents, was invested in Treasury fund accounts and $175.0 million was invested in U.S. Treasury notes under repurchase agreements and shown as Short-term investments. At December 31, 2007, all of our cash was invested in Treasury fund accounts. Due to the short-term nature of the Treasury fund accounts, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the fair market value of our Cash and cash equivalents. Since our investments under repurchase agreements are liquidated the following day at an established price, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the fair market value of our short-term investments.

Commodity risk:

Certain volumes of our gas stored underground are available for sale and subject to commodity price risk. At December 31, 2008 and 2007, approximately $0.2 million and $16.3 million of gas stored underground, which we own and carry as current Gas stored underground, was available for sale and exposed to commodity price risk. We utilize derivatives to hedge certain exposures to market price fluctuations on the anticipated operational sales of gas. Our pipelines do not take title to the natural gas which they transport and store in rendering traditional firm and interruptible storage services, therefore they do not assume the related natural gas commodity price risk associated with that gas.

The derivatives related to the sale of natural gas and cash for fuel reimbursement generally qualify for cash flow hedge accounting under SFAS No. 133 and are designated as such. The effective component of related gains and losses resulting from changes in fair values of the derivatives contracts designated as cash flow hedges are deferred as a component of Accumulated other comprehensive (loss) income. The deferred gains and losses are recognized in earnings when the anticipated transactions affect earnings. Generally, for gas sales and retained fuel, any gains and losses on the related derivatives would be recognized in Operating Revenues.

Credit risk:

We are exposed to credit risk relating to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. We have established credit policies in the pipeline tariffs which are intended to minimize credit risk in accordance with FERC policies and actively monitor this portion of our business. Our credit exposure generally relates to receivables for services provided, as well as volumes owed by customers for imbalances or gas lent by us to them, generally under PAL and no-notice services. Natural gas price volatility has increased dramatically in recent years, which has materially increased credit risk related to gas loaned to customers. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to repay the gas they owe to us, this could have a material adverse effect on our financial condition, results of operations and cash flows.

 
Mr. H. Christopher Owings
United States Securities and Exchange Commission
February 24, 2009
Page 11 of 12
 
 
As of December 31, 2008, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries due to gas imbalances was approximately 34.4 trillion British thermal units (TBtu). Assuming an average market price during December 2008 of $5.85 per million British thermal units (MMBtu), the market value of this gas at December 31, 2008, would have been approximately $201.2 million. As of December 31, 2007, the amount of gas loaned out by our subsidiaries or owed to our subsidiaries due to gas imbalances was approximately 15.2 TBtu. Assuming an average market price during December 2007 of $7.13 per MMBtu, the market value of this gas at December 31, 2007, would have been approximately $108.4 million.

More than 85% of our revenues are derived from gas marketers, LDCs and producers, the majority of which have investment grade ratings. Although nearly all of our customers pay for our services on a timely basis, we actively monitor the credit exposure to our customers. We include in our ongoing assessments amounts due pursuant to services we render plus the value of any gas we have lent to a customer through no-notice or PAL services and the value of gas due to us under a transportation imbalance. Our pipeline tariffs contain language that allow us to require a customer that does not meet certain credit criteria to provide cash collateral, post a letter of credit or provide a guarantee from a credit-worthy entity in an amount equaling up to three months of capacity reservation charges. For certain agreements associated with our expansion projects, we have included contractual provisions that require additional credit support should the credit ratings of those customers fall below investment grade.

After completion of our expansion projects, producers will comprise a larger portion of our revenues, both in aggregate as a group and separately. We expect producers as a group to contribute a more significant portion of our future revenues and one producer to represent over 10% of our total revenues. Historically producers have had lower credit ratings than LDCs and LDC-sponsored marketing companies, therefore the expected change in our customer base could result in higher total credit risk. We will continue to actively monitor the credit risks associated with our customer base.

Market risk:

Our primary exposure to market risk occurs at the time our existing transportation and storage contracts expire and are subject to termination or renegotiation.  In addition, we have market risk exposure if one of our transportation or storage customers defaults on a service agreement and we are unable to resell the capacity at the same or higher rate.  As a result of competition in the industry, we actively monitor future expiration dates associated with our contract portfolio. As of December 31, 2008, approximately 17% of the firm contract load on our pipeline systems, excluding agreements related to the expansion projects not yet in service, was due to expire on or before December 31, 2009. As of December 31, 2007, the firm contract load due to expire within one year was 25%. Many of the contracts comprising the 25% were renewed or remarketed at favorable terms and for extended terms, increasing our weighted-average contract term.

 
 
 

Mr. H. Christopher Owings
United States Securities and Exchange Commission
February 24, 2009
Page 12 of 12
 

 
*  *  *

The Company acknowledges that:
 
·  
the Company is responsible for the adequacy and accuracy of the disclosure in its filing;;
 
·  
staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the Company’s filing; and
 
·  
the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.
 
Although the Company is, of course, amenable to enhancing its disclosures in the context of the Comment letter and the Staff’s follow-up comments, if any, these responses should not be considered an indication that the Company believes any disclosures in the captioned Form 10-K and Form 10-Q filings were inadequate or incorrect in any material aspect.
 
If you have any questions or further comments, please feel free to contact me at 713-479-8082.

Very truly yours,

By:    
/s/ Jamie L. Buskill
 
Senior Vice President and Chief Financial Officer



 
 
 

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