form10q.htm
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2009
OR
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o |
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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: 000-51757
REGENCY ENERGY PARTNERS LP
(Exact name of registrant as specified in its charter)
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DELAWARE |
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16-1731691 |
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(State or other jurisdiction of incorporation or organization) |
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(I.R.S. Employer Identification No.) |
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2001 BRYAN STREET, SUITE 3700 |
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DALLAS, TX |
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75201 |
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(Address of principal executive offices) |
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(Zip Code) |
(214) 750-1771
(Registrant’s telephone number, including area code)
NONE
(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. þYes oNo
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). oYes oNo
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 small reporting company” in Rule 12b-2 of the Exchange Act.
þLarge accelerated filer oAccelerated filer oNon-accelerated filer (Do not check if a smaller reporting company) oSmaller
reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). oYes þNo
The issuer had 81,131,978 common units outstanding as of July 31, 2009.
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PART I — FINANCIAL INFORMATION |
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1 |
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23 |
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40 |
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41 |
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PART II — OTHER INFORMATION |
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41 |
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41 |
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41 |
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Item 6. Exhibits |
41 |
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Introductory Statement
References in this report to the “Partnership,” “we,” “our,” “us” and similar terms, when used in a historical context, refer to Regency Energy Partners LP. When used in the present tense or prospectively, these terms refer to the Partnership and its subsidiaries. We use
the following definitions in this quarterly report on Form 10-Q:
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Name |
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Definition or Description |
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Alinda |
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Alinda Capital Partners LLC, a Delaware limited liability company that is an independent private investment firm specializing in infrastructure investments |
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Alinda Investor I |
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Alinda Gas Pipelines I, L.P., a Delaware limited partnership |
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Alinda Investor II |
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Alinda Gas Pipelines II, L.P., a Delaware limited partnership |
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Alinda Investors |
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Alinda Investor I and Alinda Investor II, collectively |
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Bbls/d |
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Barrels per day |
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Bcf |
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One billion cubic feet |
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Bcf/d |
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One billion cubic feet per day |
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BTU |
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A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit |
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CDM |
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CDM Resource Management LLC |
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EITF |
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Emerging Issues Task Force |
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El Paso |
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El Paso Field Services, LP |
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FASB |
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Financial Accounting Standards Board |
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FERC |
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Federal Energy Regulatory Commission |
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Finance Corp. |
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Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership |
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FrontStreet |
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FrontStreet Hugoton LLC |
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FSP |
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Financial Accounting Standards Board Statement of Position |
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GAAP |
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Accounting principles generally accepted in the United States |
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GE |
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General Electric Company |
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GE EFS |
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General Electric Energy Financial Services, a unit of GECC, combined with Regency GP Acquirer LP and Regency LP Acquirer LP |
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GECC |
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General Electric Capital Corporation, an indirect wholly owned subsidiary of GE |
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General Partner |
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Regency GP LP, the general partner of the Partnership, or Regency GP LLC, the general partner of Regency GP LP, which effectively manages the business and affairs of the Partnership |
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HPC |
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RIGS Haynesville Partnership Co., a general partnership that owns 100 percent of RIGS |
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Lehman |
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Lehman Brothers Holdings, Inc. |
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LIBOR |
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London Interbank Offered Rate |
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LITP |
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Long-Term Incentive Plan |
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MMbtu |
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One million BTUs |
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MMbtu/d |
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One million BTUs per day |
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MMcf |
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One million cubic feet |
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MMcf/d |
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One million cubic feet per day |
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Nexus |
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Nexus Gas Holdings, LLC |
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NOE |
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Notice of Enforcement |
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NGLs |
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Natural gas liquids |
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Nasdaq |
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Nasdaq Stock Market, LLC |
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NYMEX |
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New York Mercantile Exchange |
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Partnership |
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Regency Energy Partners LP |
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Regency HIG |
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Regency Haynesville Intrastate Gas LLC, a wholly owned subsidiary of the Partnership |
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RFS |
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Regency Field Services LLC |
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RGS |
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Regency Gas Services LP |
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RIGS |
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Regency Intrastate Gas LP |
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SEC |
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Securities and Exchange Commission |
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SFAS |
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Statement of Financial Accounting Standard |
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Sonat |
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Southern Natural Gas Company |
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TCEQ |
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Texas Commission on Environmental Quality |
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Tcf |
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One trillion cubic feet |
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Tcf/d |
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One trillion cubic feet per day |
Cautionary Statement about Forward-Looking Statements
Certain matters discussed in this report include “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements
using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we cannot give assurances
that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions including without limitation the following:
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volatility in the price of oil, natural gas, and natural gas liquids; |
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declines in the credit markets and the availability of credit for us as well as for producers connected to our system and our customers; |
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the level of creditworthiness of, and performance by, our counterparties and customers; |
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our access to capital to fund organic growth projects and acquisitions, and our ability to obtain debt or equity financing on satisfactory terms; |
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our use of derivative financial instruments to hedge commodity and interest rate risks; |
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the amount of collateral required to be posted from time to time in our transactions; |
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changes in commodity prices, interest rates, and demand for our services; |
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changes in laws and regulations impacting the midstream sector of the natural gas industry; |
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weather and other natural phenomena; |
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· |
industry changes including the impact of consolidations and changes in competition; |
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our ability to obtain required approvals for construction or modernization of our facilities and the timing of production from such facilities; and |
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the effect of accounting pronouncements issued periodically by accounting standard setting boards. |
If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may differ materially from those anticipated, estimated, projected or expected.
Other factors that could cause our actual results to differ from our projected results are discussed in Item 1A of our December 31, 2008 Annual Report on Form 10-K.
Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
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Regency Energy Partners LP |
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Condensed Consolidated Balance Sheets |
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(unaudited) |
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(in thousands except unit data) |
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June 30, 2009 |
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December 31, 2008 |
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ASSETS |
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Current Assets: |
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Cash and cash equivalents |
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$ |
9,275 |
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$ |
599 |
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Restricted cash |
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1,510 |
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10,031 |
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Trade accounts receivable, net of allowance of $1,565 and $941 |
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28,637 |
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40,875 |
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Accrued revenues |
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62,013 |
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96,712 |
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Related party receivables |
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4,030 |
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855 |
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Assets from risk management activities |
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40,231 |
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73,993 |
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Other current assets |
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13,131 |
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13,338 |
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Total current assets |
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158,827 |
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236,403 |
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Property, Plant and Equipment: |
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Gathering and transmission systems |
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453,169 |
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652,267 |
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Compression equipment |
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821,981 |
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799,527 |
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Gas plants and buildings |
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154,561 |
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156,246 |
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Other property, plant and equipment |
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154,570 |
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167,256 |
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Construction-in-progress |
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99,431 |
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154,852 |
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Total property, plant and equipment |
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1,683,712 |
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1,930,148 |
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Less accumulated depreciation |
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(225,881 |
) |
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(226,594 |
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Property, plant and equipment, net |
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1,457,831 |
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1,703,554 |
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Other Assets: |
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Investment in unconsolidated subsidiary |
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400,023 |
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- |
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Long-term assets from risk management activities |
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13,712 |
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36,798 |
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Other, net of accumulated amortization of debt issuance costs of $7,706 and $5,246 |
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22,220 |
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13,880 |
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Total other assets |
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435,955 |
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50,678 |
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Intangible Assets and Goodwill: |
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Intangible assets, net of accumulated amortization of $27,666 and $22,667 |
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196,557 |
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205,646 |
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Goodwill |
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228,114 |
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262,358 |
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Total intangible assets and goodwill |
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424,671 |
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468,004 |
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TOTAL ASSETS |
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$ |
2,477,284 |
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$ |
2,458,639 |
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LIABILITIES & PARTNERS' CAPITAL AND NONCONTROLLING INTEREST |
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Current Liabilities: |
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Trade accounts payable |
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$ |
37,224 |
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$ |
65,483 |
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Accrued cost of gas and liquids |
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48,353 |
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76,599 |
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Related party payables |
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1,331 |
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- |
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Escrow payable |
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1,506 |
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10,031 |
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Deferred revenue, including related party amounts of $231 and $0 |
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11,196 |
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11,572 |
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Liabilities from risk management activities |
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17,193 |
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42,691 |
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Other current liabilities |
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11,703 |
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10,574 |
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Total current liabilities |
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128,506 |
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216,950 |
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Long-term liabilities from risk management activities |
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53 |
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560 |
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Other long-term liabilities |
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14,820 |
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15,487 |
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Long-term debt, net |
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1,185,385 |
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1,126,229 |
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Commitments and contingencies |
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Partners' Capital and Noncontrolling Interest: |
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Common units (81,781,105 and 55,519,903 units authorized; 81,131,978 and 54,796,701 units issued
and outstanding at June 30, 2009 and December 31, 2008) |
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|
1,079,333 |
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764,161 |
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Class D common units (7,276,506 units authorized, issued and outstanding at December 31, 2008) |
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|
- |
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|
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226,759 |
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Subordinated units (19,103,896 units authorized, issued and outstanding at December 31, 2008) |
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|
- |
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|
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(1,391 |
) |
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General partner interest |
|
|
24,864 |
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|
|
29,283 |
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Accumulated other comprehensive income |
|
|
30,304 |
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|
|
67,440 |
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Noncontrolling interest |
|
|
14,019 |
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|
|
13,161 |
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Total partners' capital and noncontrolling interest |
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1,148,520 |
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|
|
1,099,413 |
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| |
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TOTAL LIABILITIES AND PARTNERS' CAPITAL AND NONCONTROLLING INTEREST |
|
$ |
2,477,284 |
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$ |
2,458,639 |
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See accompanying notes to condensed consolidated financial statements |
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|
Regency Energy Partners LP |
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Condensed Consolidated Income Statements |
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Unaudited |
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(in thousands except unit data and per unit data) |
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| |
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Three Months Ended June 30, |
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Six Months Ended June 30, |
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2009 |
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2008 |
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2009 |
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2008 |
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REVENUES |
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Gas sales |
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$ |
106,897 |
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$ |
362,769 |
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$ |
254,793 |
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$ |
599,462 |
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NGL sales |
|
|
57,676 |
|
|
|
126,521 |
|
|
|
107,261 |
|
|
|
235,020 |
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Gathering, transportation and other fees, including related party amounts of $2,239, $935, $3,376 and $1,926 |
|
|
69,231 |
|
|
|
70,175 |
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|
|
142,079 |
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|
|
132,161 |
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Net realized and unrealized gain (loss) from risk management activities |
|
|
12,515 |
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(32,760 |
) |
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|
26,970 |
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(46,417 |
) |
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Other |
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|
7,223 |
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|
20,000 |
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|
|
12,417 |
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|
31,714 |
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Total revenues |
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253,542 |
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|
|
546,705 |
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|
|
543,520 |
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|
|
951,940 |
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OPERATING COSTS AND EXPENSES |
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Cost of sales, including related party amounts of $1,453, $844, $1,700 and $1,247 |
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|
157,347 |
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446,687 |
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|
|
339,875 |
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|
|
760,276 |
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Operation and maintenance |
|
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31,974 |
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|
|
32,516 |
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|
|
68,016 |
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|
|
61,361 |
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General and administrative |
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14,127 |
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|
13,925 |
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|
29,205 |
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|
24,809 |
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Loss (gain) on asset sales, net of costs of $372, $0, $5,530 and $0 |
|
|
651 |
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|
|
442 |
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|
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(133,280 |
) |
|
|
468 |
|
|
Management services termination fee |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,888 |
|
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Transaction expenses |
|
|
- |
|
|
|
147 |
|
|
|
- |
|
|
|
534 |
|
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Depreciation and amortization |
|
|
26,236 |
|
|
|
26,476 |
|
|
|
54,125 |
|
|
|
48,216 |
|
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Total operating costs and expenses |
|
|
230,335 |
|
|
|
520,193 |
|
|
|
357,941 |
|
|
|
899,552 |
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| |
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|
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OPERATING INCOME |
|
|
23,207 |
|
|
|
26,512 |
|
|
|
185,579 |
|
|
|
52,388 |
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| |
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|
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|
|
|
|
|
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Income from unconsolidated subsidiary |
|
|
1,587 |
|
|
|
- |
|
|
|
1,923 |
|
|
|
- |
|
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Interest expense, net |
|
|
(19,568 |
) |
|
|
(16,782 |
) |
|
|
(33,795 |
) |
|
|
(32,188 |
) |
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Other income and deductions, net |
|
|
214 |
|
|
|
132 |
|
|
|
256 |
|
|
|
332 |
|
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INCOME BEFORE INCOME TAXES |
|
|
5,440 |
|
|
|
9,862 |
|
|
|
153,963 |
|
|
|
20,532 |
|
|
Income tax expense (benefit) |
|
|
(515 |
) |
|
|
(41 |
) |
|
|
(416 |
) |
|
|
209 |
|
|
NET INCOME |
|
|
5,955 |
|
|
|
9,903 |
|
|
|
154,379 |
|
|
|
20,323 |
|
|
Net loss (income) attributable to noncontrolling interest |
|
|
(65 |
) |
|
|
69 |
|
|
|
(100 |
) |
|
|
(3 |
) |
|
NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP |
|
$ |
5,890 |
|
|
$ |
9,972 |
|
|
$ |
154,279 |
|
|
$ |
20,320 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner's interest, including IDR |
|
|
741 |
|
|
|
727 |
|
|
|
4,274 |
|
|
|
1,634 |
|
|
Allocation of net income to non-vested common units |
|
|
(137 |
) |
|
|
71 |
|
|
|
1,217 |
|
|
|
163 |
|
|
Beneficial conversion feature for Class D common units |
|
|
- |
|
|
|
1,866 |
|
|
|
820 |
|
|
|
3,425 |
|
|
Limited partners' interest |
|
$ |
5,286 |
|
|
$ |
7,308 |
|
|
$ |
147,968 |
|
|
$ |
15,098 |
|
| |
|
|
|
|
|
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|
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Basic and Diluted earnings per unit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
Amount allocated to common and subordinated units |
|
$ |
5,286 |
|
|
$ |
7,308 |
|
|
$ |
147,968 |
|
|
$ |
15,098 |
|
|
Weighted average number of common and subordinated units outstanding |
|
|
80,550,149 |
|
|
|
62,175,856 |
|
|
|
78,920,074 |
|
|
|
60,702,682 |
|
|
Basic income per common and subordinated unit |
|
$ |
0.07 |
|
|
$ |
0.12 |
|
|
$ |
1.87 |
|
|
$ |
0.25 |
|
|
Diluted income per common and subordinated unit |
|
$ |
0.06 |
|
|
$ |
0.12 |
|
|
$ |
1.85 |
|
|
$ |
0.25 |
|
|
Distributions per unit |
|
$ |
0.445 |
|
|
$ |
0.445 |
|
|
$ |
0.89 |
|
|
$ |
0.865 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount allocated to Class D common units |
|
$ |
- |
|
|
$ |
1,866 |
|
|
$ |
820 |
|
|
$ |
3,425 |
|
|
Total number of Class D common units outstanding |
|
|
- |
|
|
|
7,276,506 |
|
|
|
7,276,506 |
|
|
|
7,276,506 |
|
|
Income per Class D common unit due to beneficial conversion feature |
|
$ |
- |
|
|
$ |
0.26 |
|
|
$ |
0.11 |
|
|
$ |
0.47 |
|
|
Distributions per unit |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial statements |
|
|
Regency Energy Partners LP |
|
|
Condensed Consolidated Statements of Comprehensive Income (Loss) |
|
|
Unaudited |
|
|
(in thousands) |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
| |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
5,955 |
|
|
$ |
9,903 |
|
|
$ |
154,379 |
|
|
$ |
20,323 |
|
|
Net hedging amounts reclassified to earnings |
|
|
(13,644 |
) |
|
|
15,167 |
|
|
|
(27,894 |
) |
|
|
25,602 |
|
|
Net change in fair value of cash flow hedges |
|
|
(14,622 |
) |
|
|
(47,071 |
) |
|
|
(9,242 |
) |
|
|
(49,905 |
) |
|
Comprehensive income (loss) |
|
$ |
(22,311 |
) |
|
$ |
(22,001 |
) |
|
$ |
117,243 |
|
|
$ |
(3,980 |
) |
|
Comprehensive (income) loss attributable to noncontrolling interest |
|
|
(65 |
) |
|
|
69 |
|
|
|
(100 |
) |
|
|
(3 |
) |
|
Comprehensive income (loss) attributable to Regency Energy Partners LP |
|
$ |
(22,376 |
) |
|
$ |
(21,932 |
) |
|
$ |
117,143 |
|
|
$ |
(3,983 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial statements |
|
|
Regency Energy Partners LP |
|
|
Condensed Consolidated Statements of Cash Flows |
|
|
Unaudited |
|
|
(in thousands) |
|
| |
|
|
|
|
|
|
| |
|
Six Months Ended June 30, |
|
| |
|
2009 |
|
|
2008 |
|
|
OPERATING ACTIVITIES |
|
|
|
|
|
|
|
Net income |
|
$ |
154,379 |
|
|
$ |
20,323 |
|
|
Adjustments to reconcile net income to net cash flows provided by operating activities: |
|
|
|
|
|
|
|
|
|
Depreciation and amortization, including debt issuance cost amortization |
|
|
56,750 |
|
|
|
49,598 |
|
|
Noncash income from unconsolidated subsidiary |
|
|
(23 |
) |
|
|
- |
|
|
Risk management portfolio valuation changes |
|
|
(6,293 |
) |
|
|
20,582 |
|
|
Loss (gain) on asset sales, net |
|
|
(133,280 |
) |
|
|
468 |
|
|
Unit based compensation expenses |
|
|
2,750 |
|
|
|
1,839 |
|
|
Cash flow changes in current assets and liabilities: |
|
|
|
|
|
|
|
|
|
Trade accounts receivable, accrued revenues, and related party receivables |
|
|
38,073 |
|
|
|
(72,784 |
) |
|
Other current assets |
|
|
3,728 |
|
|
|
(2,914 |
) |
|
Trade accounts payable, accrued cost of gas and liquids, and related party payables |
|
|
(38,809 |
) |
|
|
53,088 |
|
|
Other current liabilities |
|
|
(7,396 |
) |
|
|
15,314 |
|
|
Other assets and liabilities |
|
|
(608 |
) |
|
|
1,420 |
|
|
Net cash flows provided by operating activities |
|
|
69,271 |
|
|
|
86,934 |
|
| |
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(119,185 |
) |
|
|
(148,888 |
) |
|
Acquisitions |
|
|
- |
|
|
|
(577,345 |
) |
|
Proceeds from asset sales |
|
|
83,182 |
|
|
|
580 |
|
|
Net cash flows used in investing activities |
|
|
(36,003 |
) |
|
|
(725,653 |
) |
| |
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
Net (repayments) borrowings under revolving credit facilities |
|
|
(177,249 |
) |
|
|
681,000 |
|
|
Proceeds from issuance of senior notes, net of discount |
|
|
236,240 |
|
|
|
- |
|
|
Debt issuance costs |
|
|
(11,939 |
) |
|
|
(3,313 |
) |
|
Partner contributions |
|
|
- |
|
|
|
7,663 |
|
|
Partner distributions |
|
|
(71,644 |
) |
|
|
(52,317 |
) |
|
Proceeds from option exercises |
|
|
- |
|
|
|
2,700 |
|
|
Net cash flows (used in) provided by financing activities |
|
|
(24,592 |
) |
|
|
635,733 |
|
| |
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
8,676 |
|
|
|
(2,986 |
) |
|
Cash and cash equivalents at beginning of period |
|
|
599 |
|
|
|
32,971 |
|
|
Cash and cash equivalents at end of period |
|
$ |
9,275 |
|
|
$ |
29,985 |
|
| |
|
|
|
|
|
|
|
|
|
Supplemental cash flow information: |
|
|
|
|
|
|
|
|
|
Interest paid, net of amounts capitalized |
|
$ |
28,374 |
|
|
$ |
28,222 |
|
|
Income taxes paid |
|
|
- |
|
|
|
564 |
|
|
Non-cash capital expenditures in accounts payable |
|
|
9,480 |
|
|
|
17,907 |
|
|
Issuance of common units for an acquisition |
|
|
- |
|
|
|
219,590 |
|
|
Contribution of fixed assets, goodwill and working capital to RIGS Haynesville Partnership Co. |
|
|
261,019 |
|
|
|
- |
|
| |
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial statements |
|
|
Regency Energy Partners LP |
|
|
Condensed Consolidated Statements of Partners' Capital and Noncontrolling Interest |
|
|
Unaudited |
|
|
(in thousands except unit data) |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Regency Energy Partners LP |
|
|
|
|
|
|
|
| |
|
Units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Common |
|
|
Class D |
|
|
Subordinated |
|
|
Common Unitholders |
|
|
Class D Unitholders |
|
|
Subordinated Unitholders |
|
|
General Partner Interest |
|
|
Accumulated Other Comprehensive Income |
|
|
Noncontrolling Interest |
|
|
Total |
|
|
Balance - December 31, 2008 |
|
|
54,796,701 |
|
|
|
7,276,506 |
|
|
|
19,103,896 |
|
|
$ |
764,161 |
|
|
$ |
226,759 |
|
|
$ |
(1,391 |
) |
|
$ |
29,283 |
|
|
$ |
67,440 |
|
|
$ |
13,161 |
|
|
$ |
1,099,413 |
|
|
Revision of partner interest |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
6,073 |
|
|
|
- |
|
|
|
- |
|
|
|
(6,073 |
) |
|
|
- |
|
|
|
|
|
|
|
- |
|
|
Issuance of non-vested common units, net of forfeitures |
|
|
(45,125 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Conversion of subordinated units |
|
|
19,103,896 |
|
|
|
|
|
|
|
(19,103,896 |
) |
|
|
(1,391 |
) |
|
|
- |
|
|
|
1,391 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Unit based compensation expenses |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,750 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,750 |
|
|
Partner distributions |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(69,024 |
) |
|
|
- |
|
|
|
- |
|
|
|
(2,620 |
) |
|
|
- |
|
|
|
- |
|
|
|
(71,644 |
) |
|
Net income |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
149,185 |
|
|
|
820 |
|
|
|
- |
|
|
|
4,274 |
|
|
|
- |
|
|
|
100 |
|
|
|
154,379 |
|
|
Conversion of Class D common units |
|
|
7,276,506 |
|
|
|
(7,276,506 |
) |
|
|
- |
|
|
|
227,579 |
|
|
|
(227,579 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Contributions from noncontrolling interest |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
758 |
|
|
|
758 |
|
|
Net hedging amounts reclassified to earnings |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(27,894 |
) |
|
|
- |
|
|
|
(27,894 |
) |
|
Net change in fair value of cash flow hedges |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(9,242 |
) |
|
|
- |
|
|
|
(9,242 |
) |
|
Balance - June 30, 2009 |
|
|
81,131,978 |
|
|
|
- |
|
|
|
- |
|
|
$ |
1,079,333 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
24,864 |
|
|
$ |
30,304 |
|
|
$ |
14,019 |
|
|
$ |
1,148,520 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial statements |
|
Regency Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements
1. Organization and Summary of Significant Accounting Policies
Organization. The unaudited condensed consolidated financial statements presented herein contain the results of Regency Energy Partners LP and its subsidiaries. The Partnership and its subsidiaries are engaged in the business of gathering and processing, contract
compression, and transporting of natural gas and NGLs.
The unaudited financial information as of, and for the three and six months ended June 30, 2009 has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2008, as amended by Form 8-K filed on May 14, 2009. In
the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to
the rules and regulations of the SEC.
Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP and, of necessity, include the use of estimates and assumptions by management. Actual results could differ from these estimates.
Equity Method Investments. The equity method of accounting is used to account for the Partnership’s interest in investments greater than 20 percent voting stock of an investee and where the Partnership lacks control over the investee.
Intangible Assets. Intangible assets, net consist of the following.
| |
|
Permits and Licenses |
|
|
Customer Contracts |
|
|
Trade Names |
|
|
Customer Relations |
|
|
Total |
|
| |
|
(in thousands) |
|
|
Balance at December 31, 2008 |
|
$ |
8,582 |
|
|
$ |
126,799 |
|
|
$ |
32,848 |
|
|
$ |
37,417 |
|
|
$ |
205,646 |
|
|
Disposals |
|
|
(2,920 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(2,920 |
) |
|
Amortization |
|
|
(313 |
) |
|
|
(3,612 |
) |
|
|
(1,170 |
) |
|
|
(1,074 |
) |
|
|
(6,169 |
) |
|
Balance at June 30, 2009 |
|
$ |
5,349 |
|
|
$ |
123,187 |
|
|
$ |
31,678 |
|
|
$ |
36,343 |
|
|
$ |
196,557 |
|
The weighted average amortization period for permits and licenses, customer contracts, trade names, and customer relations are 15, 24, 15, and 19 years, respectively. Permits and licenses are generally renewed with minimal expense as a charge to operating and maintenance expense in the period incurred. Regarding customer
contracts, the actual remaining lives of the contracts were used to evaluate the cash flows expected with no renewal assumption. The trade name and customer relations intangible assets use the going concern assumption with no renewal cost. The expected amortization of the intangible assets for each of the five succeeding years is as follows.
|
Year ending December 31, |
|
Total |
|
| |
|
(in thousands) |
|
|
2009 (remaining) |
|
$ |
6,043 |
|
|
2010 |
|
|
12,086 |
|
|
2011 |
|
|
10,828 |
|
|
2012 |
|
|
10,535 |
|
|
2013 |
|
|
10,535 |
|
Revision to Partners' Capital Accounts. In 2009, the Partnership revised the allocation of net income between the general partner and common unit holders from a previous period to reflect the income allocation provisions of the Partnership agreement. The
effect of this revision is not material to the prior financial statements.
Recently Issued Accounting Standards. In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”), which significantly changes the accounting for business acquisitions both during the period of the acquisition and in subsequent
periods. The Partnership adopted SFAS 141(R) on January 1, 2009.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS 160”), which significantly changes the accounting and reporting related to noncontrolling interests in a consolidated subsidiary. The Partnership adopted SFAS
160 for all periods presented. This statement requires the recognition of a noncontrolling interest (formerly styled as a minority interest) in partners’ capital in the condensed consolidated financial statements and separate from the partners’ interest. Also, the amount of net income attributable to the noncontrolling interest is included in the consolidated net income on the face of the condensed consolidated income statement.
In March 2008, the FASB issued EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” (“EITF 07-4”). EITF 07-4 defines how to allocate net income among the various classes of equity, including incentive distribution rights (or “IDRs”), narrowing
the number of currently acceptable methods. The standard became effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application was not permitted, and EITF 07-4 must be applied retrospectively for all financial statements presented. The adoption of this standard changes the Partnership’s method of allocating net income for earnings per unit purposes to holders of the IDRs in
periods where net income exceeds cash distributed. Because the Partnership Agreement restricts the amount of distributions to holders of IDRs based on cash available for distribution, undistributed net income will be allocated based on each class of security’s ownership interest. Further, because the IDR's are deemed to have no ownership interest, no undistributed net income will be allocated to this class of security. All prior period earnings per unit data have been adjusted.
In April 2008, FASB issued FSP No. 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP 142-3”), which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of intangible assets. The objective of FSP 142-3 is to better
match the useful life of intangible assets to the cash flow generated. FSP 142-3 became effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. The adoption of FSP 142-3 did not impact the Partnership’s financial position, results of operations or cash flows.
In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”), which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity of GAAP. SFAS
162’s effective date is November 15, 2008. The adoption of SFAS 162 had no impact on the Partnership’s financial position, results of operations or cash flows.
In June 2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”) and is effective for fiscal years beginning after December 15, 2008. The adoption of this standard was applied retrospectively and had
an immaterial impact on the Partnership’s earnings per unit.
In April 2009, the FASB issued FSP FAS 107-1, “Interim Disclosures about Fair Value of Financial Instruments,” which is effective for interim periods ending after June 15, 2009. The adoption of this standard, which requires publicly traded companies to make fair value disclosures in interim periods, had no impact on the Partnership’s
financial position, results of operations or cash flows.
In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS 165”), which requires public entities to evaluate subsequent events through the date through which financial statements are issued. SFAS 165 is effective for interim and annual periods ending after June 15, 2009. The adoption
of SFAS 165 did not impact the Partnership’s financial position, results of operations or cash flows.
In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R) (“FASB 167”), which significantly changes the consolidation model for variable interest entities. SFAS 167 shall be effective for annual reporting period that begins after November 15, 2009, and for interim periods within that
first annual reporting period. The Partnership is currently evaluating the potential impact of this standard on its financial position, results of operations or cash flows.
In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification TM and the Hierarchy of Generally Accepted Accounting Principles, a replacement of SFAS No. 162” (the “Codification”). The Codification will
be the single source for GAAP that integrates existing standards and organizes them into accounting topics. The Codification is not intended to change GAAP but will change how GAAP is referenced in the financial statements. The Codification will become effective for financial statements issued for interim and annual periods ending after September 15, 2009, and it is not expected to have a material impact on the Partnership’s financial position, results of operations or cash flows.
2. Income per Limited Partner Unit
The Partnership issued 7,276,506 Class D common units in connection with the CDM acquisition. At the commitment date, the sales price of $30.18 per unit represented a $1.10 discount from the fair value of the Partnership’s common units. Under EITF No. 98-5, “Accounting for Convertible Securities with Beneficial
Conversion Features or Contingently Adjustable Conversion Ratios,” the discount represented a beneficial conversion feature that is treated as a non-cash distribution for purposes of calculating earnings per unit. The beneficial conversion feature is reflected in income per unit using the effective yield method over the period the Class D common units are outstanding, as indicated on the statements of operations in the line item entitled “beneficial conversion feature for Class D common
units.” The Class D common units converted to common units on a one-for-one basis on February 9, 2009.
The following tables provide a reconciliation of the basic and diluted earnings per unit computations.
| |
|
For the Three Months Ended June 30, 2009 |
|
|
For the Three Months Ended June 30, 2008 |
|
| |
|
Income (Numerator) |
|
Units (Denominator) |
|
Per-Unit Amount |
|
Income (Numerator) |
|
Units (Denominator) |
|
Per-Unit Amount |
|
| |
|
(in thousands except unit and per unit data) |
|
|
Basic Earnings per Unit |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Limited Partner interests |
|
$ |
5,286 |
|
|
|
80,550,149 |
|
|
$ |
0.07 |
|
|
$ |
7,308 |
|
|
|
62,175,856 |
|
|
$ |
0.12 |
|
|
Effect of Dilutive Securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested common units |
|
|
(137 |
) |
|
|
621,337 |
|
|
|
|
|
|
|
71 |
|
|
|
705,145 |
|
|
|
|
|
|
Diluted Earnings per Unit |
|
$ |
5,149 |
|
|
|
81,171,486 |
|
|
$ |
0.06 |
|
|
$ |
7,379 |
|
|
|
62,881,001 |
|
|
$ |
0.12 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
For the Six Months Ended June 30, 2009 |
|
|
For the Six Months Ended June 30, 2008 |
|
| |
|
Income (Numerator) |
|
Units (Denominator) |
|
Per-Unit Amount |
|
Income (Numerator) |
|
Units (Denominator) |
|
Per-Unit Amount |
|
| |
|
(in thousands except unit and per unit data) |
|
|
Basic Earnings per Unit |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Limited Partner interests |
|
$ |
147,968 |
|
|
|
78,920,074 |
|
|
$ |
1.87 |
|
|
$ |
15,098 |
|
|
|
60,702,682 |
|
|
$ |
0.25 |
|
|
Effect of Dilutive Securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested common units |
|
|
1,217 |
|
|
|
652,740 |
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
Common unit options |
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
- |
|
|
|
149,186 |
|
|
|
|
|
|
Class D common units |
|
|
820 |
|
|
|
1,608,068 |
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
Diluted Earnings per Unit |
|
$ |
150,005 |
|
|
|
81,180,882 |
|
|
$ |
1.85 |
|
|
$ |
15,098 |
|
|
|
60,851,868 |
|
|
$ |
0.25 |
|
The following table shows securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive.
| |
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
| |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Non-vested common units |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
713,925 |
|
|
Common unit options |
|
|
372,768 |
|
|
|
- |
|
|
|
376,518 |
|
|
|
- |
|
|
Class D common units |
|
|
- |
|
|
|
7,276,506 |
|
|
|
- |
|
|
|
7,276,506 |
|
|
Phantom units |
|
|
332,860 |
|
|
|
- |
|
|
|
332,860 |
|
|
|
- |
|
3. Acquisitions and Disposition
On March 17, 2009, the Partnership announced the completion of the transactions contemplated by the Contribution Agreement (the “Contribution Agreement”) relating to a new joint venture arrangement among Regency HIG, EFS Haynesville, LLC, a 100 percent owned subsidiary of GECC, and the Alinda Investors. The Partnership
contributed RIGS, which owns the Regency Intrastate Gas System, valued at $400,000,000, to HPC, in exchange for a 38 percent interest in HPC. EFS Haynesville, LLC and the Alinda Investors contributed $126,500,000 and $526,500,000 in cash, respectively, to HPC in return for a 12 percent and a 50 percent interest, respectively. In accordance with SFAS 160, the disposition and deconsolidation resulted in the recording of a $133,451,000 gain (of which $52,813,000 represents the remeasurement
of the Partnership’s retained 38 percent interest to its fair value), net of transaction costs of $5,530,000.
The following unaudited pro forma financial information has been prepared as if the acquisitions of FrontStreet, CDM and Nexus and the contribution of RIGS to HPC had occurred as of the beginning of the earliest period presented. Such unaudited pro forma financial information does not purport to be indicative of the results of operations
that would have been achieved if the transactions to which the Partnership is giving pro forma effect actually occurred on the date referred to above or the results of operations that may be expected in the future.
| |
|
Pro Forma Results for the |
|
|
Pro Forma Results for the |
|
| |
|
Three Months Ended |
|
|
Six Months Ended |
|
| |
|
June 30, 2009 |
|
|
June 30, 2008 |
|
|
June 30, 2009 |
|
|
June 30, 2008 |
|
| |
|
(in thousands except unit and per unit data) |
|
|
Revenue |
|
$ |
253,542 |
|
|
$ |
535,344 |
|
|
$ |
531,547 |
|
|
$ |
935,793 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to Regency Energy Partners LP |
|
$ |
5,890 |
|
|
$ |
1,542 |
|
|
$ |
16,325 |
|
|
$ |
143,608 |
|
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner's interest, including IDR |
|
|
741 |
|
|
|
559 |
|
|
|
1,515 |
|
|
|
4,101 |
|
|
Allocation of net income to non-vested common units |
|
|
(137 |
) |
|
|
(8 |
) |
|
|
30 |
|
|
|
1,588 |
|
|
Beneficial conversion feature for Class D common units |
|
|
- |
|
|
|
1,866 |
|
|
|
820 |
|
|
|
3,425 |
|
|
Limited partners' interest |
|
$ |
5,286 |
|
|
$ |
(875 |
) |
|
$ |
13,960 |
|
|
$ |
134,494 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted earnings per unit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount allocated to common and subordinated units |
|
$ |
5,286 |
|
|
$ |
(875 |
) |
|
$ |
13,960 |
|
|
$ |
134,494 |
|
|
Weighted average number of common and subordinated units outstanding |
|
|
80,550,149 |
|
|
|
62,175,856 |
|
|
|
78,920,074 |
|
|
|
60,702,682 |
|
|
Basic income (loss) per common and subordinated unit |
|
$ |
0.07 |
|
|
$ |
(0.01 |
) |
|
$ |
0.18 |
|
|
$ |
2.22 |
|
|
Diluted income per common and subordinated unit |
|
$ |
0.06 |
|
|
|
- |
|
|
$ |
0.18 |
|
|
$ |
1.93 |
|
|
Distributions per unit |
|
$ |
0.445 |
|
|
$ |
0.445 |
|
|
$ |
0.89 |
|
|
$ |
0.865 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount allocated to Class D common units |
|
$ |
- |
|
|
$ |
1,866 |
|
|
$ |
820 |
|
|
$ |
3,425 |
|
|
Total number of Class D common units outstanding |
|
|
- |
|
|
|
7,276,506 |
|
|
|
7,276,506 |
|
|
|
7,276,506 |
|
|
Basic and diluted income per Class D common unit due to beneficial conversion feature |
|
$ |
- |
|
|
$ |
0.26 |
|
|
$ |
0.11 |
|
|
$ |
0.47 |
|
|
Distributions per unit |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
4. Investment in Unconsolidated Subsidiary
As described in the Acquisitions and Disposition footnote, the Partnership contributed RIGS to HPC for a 38 percent partner interest in HPC. The summarized financial information of HPC as of June 30, 2009 and for the period from inception (March 18, 2009) to June 30, 2009 is disclosed below. The Partnership recognized
$1,923,000 in income from unconsolidated subsidiary for its 38 percent ownership interest from inception (March 18, 2009) to June 30, 2009.
|
RIGS Haynesville Partnership Co. |
|
|
Condensed Consolidated Balance Sheet |
|
|
Unaudited |
|
|
(in thousands) |
|
| |
|
June 30, 2009 |
|
|
ASSETS |
|
|
|
|
Total current assets |
|
$ |
365,623 |
|
|
Property, plant and equipment, net |
|
|
682,094 |
|
|
Total other assets |
|
|
55,905 |
|
|
TOTAL ASSETS |
|
$ |
1,103,622 |
|
| |
|
|
|
|
|
LIABILITIES & PARTNERS' CAPITAL |
|
|
|
|
|
Total current liabilities |
|
$ |
50,560 |
|
|
Partners' capital |
|
|
1,053,062 |
|
|
TOTAL LIABILITIES & PARTNERS' CAPITAL |
|
$ |
1,103,622 |
|
|
Condensed Income Statement |
|
|
From Inception (March 18, 2009) to June 30, 2009 |
|
|
Unaudited |
|
|
(in thousands) |
|
| |
|
|
|
|
From Inception |
|
| |
|
Three Months Ended |
|
|
(March 18, 2009) to |
|
| |
|
June 30, 2009 |
|
|
June 30, 2009 |
|
| |
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
11,707 |
|
|
$ |
13,533 |
|
|
Total operating costs and expenses |
|
|
8,038 |
|
|
|
9,084 |
|
|
OPERATING INCOME |
|
|
3,669 |
|
|
|
4,449 |
|
|
Other income and deductions, net |
|
|
508 |
|
|
|
612 |
|
|
NET INCOME |
|
$ |
4,177 |
|
|
$ |
5,061 |
|
5. Risk Management Activities
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires enhanced disclosures about derivative and hedging activities. The Partnership adopted this standard as of January
1, 2009 and its adoption had no impact on its financial position, results of operations or cash flows.
Risk and Accounting Policies. The Partnership established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit, and interest rates. The Partnership’s General Partner
is responsible for delegation of transaction authority levels, and the Risk Management Committee of the General Partner is responsible for the overall management of these risks, including monitoring exposure limits. The Risk Management Committee receives regular briefings on positions and exposures, credit exposures, and overall risk management in the context of market activities.
The Partnership primarily deals with financial institutions when entering into financial derivatives.
Commodity Price Risk. The Partnership is exposed to the impact of market fluctuations in the prices of natural gas, NGLs, and other commodities as a result of our gathering and processing activities, and the Partnership is a net seller of natural gas, NGLs and condensate. The
Partnership attempts to mitigate commodity price risk exposure by matching pricing terms between its purchases and sales of commodities. To the extent that the Partnership sells commodities in which pricing terms cannot be matched and there is a substantial risk of price exposure, the Partnership attempts to use financial hedges to mitigate the risk. It is the Partnership’s policy not to take any speculative positions with their derivative contracts. In some cases, the Partnership
may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk.
Both the Partnership’s profitability and cash flows are affected by volatility in prevailing natural gas and NGL prices. Natural gas and NGL prices are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. Adverse effects on cash flows from reductions in natural gas
and NGL product prices could adversely affect the Partnership’s ability to make distributions to unitholders. The Partnership manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts.
The Partnership has executed swap contracts settled against condensate, ethane, propane, butane, natural gas, and natural gasoline market prices. The Partnership hedged its expected exposure to declines in prices for natural gas, NGLs and condensate volumes produced for its account in the approximate percentages set for below:
| |
|
As of June 30, 2009 |
|
|
As of July 31, 2009 |
|
| |
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
NGLs |
|
|
97% |
|
|
|
37% |
|
|
|
97% |
|
|
|
56% |
|
|
|
18% |
|
|
Condensate |
|
|
76% |
|
|
|
76% |
|
|
|
76% |
|
|
|
76% |
|
|
|
18% |
|
|
Natural gas |
|
|
85% |
|
|
|
44% |
|
|
|
85% |
|
|
|
44% |
|
|
|
0% |
|
Effective June 19, 2007, the Partnership elected to account for all outstanding commodity hedging instruments on a mark-to-market basis except for the portion pursuant to which all NGL products for a particular year were hedged and the hedging relationship was, for accounting purposes, effective. The swaps continued to serve as
economic hedges against price exposure for the Partnership. At June 30, 2009, the Partnership has the following commodity swaps that qualify as cash flow hedges: the 2009 NGLs, natural gas and West Texas Intermediate crude oil hedging programs and the 2010 natural gas and West Texas Intermediate crude oil hedging programs.
In March 2008, the Partnership entered offsetting trades against its existing 2009 NGL portfolio of mark-to-market hedges, which it believes will substantially reduce the volatility of its 2009 NGL hedges. This group of trades, along with the pre-existing 2009 NGL portfolio, will continue to be accounted for on a mark-to-market
basis. Simultaneously, the Partnership executed additional 2009 NGL swaps which were designated as cash flow hedges. In May 2008, the Partnership entered into commodity swaps to hedge a portion of its 2010 NGL commodity risk, except for ethane, which are accounted for using the mark-to-market accounting treatment.
The Partnership accounts for a portion of its West Texas Intermediate crude oil swaps using mark-to-market accounting. In August 2008, the Partnership entered into an offsetting trade against its existing 2009 West Texas Intermediate crude oil swap to minimize the volatility of the original 2009 swap. Simultaneously,
the Partnership executed an additional 2009 West Texas Intermediate crude oil swap, which was designated as a cash flow hedge. In May 2008, the Partnership entered into a West Texas Intermediate crude oil swap to hedge its 2010 condensate price risk, which was designated as a cash flow hedge.
In December 2008, the Partnership entered into two natural gas swaps to hedge its equity exposure to natural gas for 2009. These natural gas swaps were designated as cash flow hedges.
In May 2009, the Partnership entered into a natural gas swap to hedge a portion of its equity exposure to natural gas for 2010. This natural gas swap was designated as a cash flow hedge.
In July 2009, the Partnership entered offsetting trades against half of its existing 2010 NGL portfolio of mark-to-market hedges, which it believes will substantially reduce the volatility of its 2010 NGL hedges. This group of trades, along with the pre-existing 2010 NGL portfolio, will continue to be accounted for on a mark-to-market
basis. Simultaneously, the Partnership executed additional 2010 NGL swaps which were designated as cash flow hedges.
Additionally, in July 2009, the Partnership entered into swap transactions to hedge a portion of its forecasted NGLs and condensate equity exposure for the first half of 2011. These swaps are accounted for using the mark-to-market accounting treatment.
Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its existing credit facility. As of June 30, 2009, the Partnership had $591,479,000 of outstanding long-term balances exposed to variable interest rate
risk. An increase of 100 basis points in the LIBOR rate would increase the Partnership’s annual payment by $5,915,000. On February 29, 2008, the Partnership entered into two-year interest rate swaps related to $300,000,000 of borrowings under its revolving credit facility, effectively locking the base rate for these borrowings at 2.4 percent, plus the applicable margin (3 percent as of June 30, 2009) through March 5, 2010. These interest rate swaps were designated as cash
flow hedges.
Credit Risk. The Partnership’s resale of natural gas exposes it to credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore a credit loss can be very large relative to overall profitability on these transactions. The
Partnership attempts to ensure that it issues credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral such as a letter of credit or a parental guarantee.
The Partnership is exposed to credit risk from its derivative counterparties. The Partnership does not require collateral from these counterparties. The Partnership has entered into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract receivables and payables
in the event of default by either party. If the Partnership's counterparties failed to perform under existing swap contracts, the Partnership's maximum loss is $54,733,000, which would be reduced by $13,666,000 due to the netting feature. The Partnership has elected to present assets and liabilities under Master ISDA Agreements gross on the condensed consolidated balance sheet.
Quantitative Disclosures. The Partnership expects to reclassify $27,334,000 of net hedging gains to revenues or interest expense from accumulated other comprehensive income in the next twelve months.
The Partnership’s risk management activities assets and liabilities, including its SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) credit risk adjustment, are detailed below for the periods ended June 30, 2009 and December 31, 2008.
| |
|
Assets |
|
|
Liabilities |
|
| |
|
June 30, 2009 |
|
|
December 31, 2008 |
|
|
June 30, 2009 |
|
|
December 31, 2008 |
|
| |
|
(in thousands) |
|
|
Derivatives designated as cash flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current amounts from risk management activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
3,767 |
|
|
$ |
4,680 |
|
|
Commodity contracts |
|
|
30,487 |
|
|
|
59,882 |
|
|
|
54 |
|
|
|
- |
|
|
Long-term amounts from risk management activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
560 |
|
|
Commodity contracts |
|
|
5,312 |
|
|
|
13,373 |
|
|
|
53 |
|
|
|
- |
|
|
Total cash flow hedging instruments |
|
|
35,799 |
|
|
|
73,255 |
|
|
|
3,874 |
|
|
|
5,240 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as cash flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current amounts from risk management activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Commodity contracts |
|
|
10,534 |
|
|
|
16,001 |
|
|
|
13,612 |
|
|
|
38,402 |
|
|
Long-term amounts from risk management activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Commodity contracts |
|
|
8,400 |
|
|
|
23,425 |
|
|
|
- |
|
|
|
- |
|
|
Total derivatives not designated as cash flow hedges |
|
|
18,934 |
|
|
|
39,426 |
|
|
|
13,612 |
|
|
|
38,402 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SFAS 157 Credit Risk Assessment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current amounts from risk management activities |
|
|
(790 |
) |
|
|
(1,890 |
) |
|
|
(240 |
) |
|
|
(391 |
) |
|
Total derivatives |
|
$ |
53,943 |
|
|
$ |
110,791 |
|
|
$ |
17,246 |
|
|
$ |
43,251 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Partnership’s condensed consolidated statement of accumulated other comprehensive income (loss) and condensed consolidated income statements for the periods ended June 30, 2009 and 2008 were impacted by risk management activities as follows (in thousands).
|
Derivatives designated as cash flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended June 30, 2009 |
|
|
Three Months Ended June 30, 2008 |
|
| |
|
Interest Rate |
|
Commodity |
|
|
Total |
|
|
Interest Rate |
|
Commodity |
|
Total |
|
|
Gain (loss) recognized in accumulated OCI (Effective) |
|
$ |
(676 |
) |
|
$ |
(13,946 |
) |
|
$ |
(14,622 |
) |
|
$ |
4,865 |
|
|
$ |
(51,936 |
) |
|
$ |
(47,071 |
) |
|
Gain (loss) reclassified from accumulated OCI into income (Effective) |
|
|
(1,515 |
) |
|
|
15,546 |
|
|
|
14,031 |
|
|
|
171 |
|
|
|
(15,277 |
) |
|
|
(15,106 |
) |
|
Gain recognized in income (Ineffective) |
|
|
- |
|
|
|
1,616 |
|
|
|
1,616 |
|
|
|
- |
|
|
|
262 |
|
|
|
262 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Six Months Ended June 30, 2009 |
|
|
Six Months Ended June 30, 2008 |
|
| |
|
Interest Rate |
|
Commodity |
|
|
Total |
|
|
Interest Rate |
|
Commodity |
|
Total |
|
|
Gain (loss) recognized in accumulated OCI (Effective) |
|
$ |
(1,514 |
) |
|
$ |
(7,728 |
) |
|
$ |
(9,242 |
) |
|
|
4,444 |
|
|
|
(54,349 |
) |
|
$ |
(49,905 |
) |
|
Gain (loss) reclassified from accumulated OCI into income (Effective) |
|
|
(2,987 |
) |
|
|
32,065 |
|
|
|
29,078 |
|
|
|
359 |
|
|
|
(25,844 |
) |
|
|
(25,485 |
) |
|
Gain recognized in income (Ineffective) |
|
|
- |
|
|
|
2,231 |
|
|
|
2,231 |
|
|
|
- |
|
|
|
486 |
|
|
|
486 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as cash flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended June 30, 2009 |
|
|
Three Months Ended June 30, 2008 |
|
| |
|
Interest Rate |
|
Commodity |
|
|
Total |
|
|
Interest Rate |
|
Commodity |
|
Total |
|
|
Loss from dedesignation amortized from accumulated OCI into income |
|
$ |
- |
|
|
$ |
(387 |
) |
|
$ |
(387 |
) |
|
$ |
- |
|
|
$ |
(61 |
) |
|
$ |
(61 |
) |
|
Loss recognized in income |
|
|
- |
|
|
|
(5,690 |
) |
|
|
(5,690 |
) |
|
|
- |
|
|
|
(18,632 |
) |
|
|
(18,632 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Six Months Ended June 30, 2009 |
|
|
Six Months Ended June 30, 2008 |
|
| |
|
Interest Rate |
|
Commodity |
|
|
Total |
|
|
Interest Rate |
|
Commodity |
|
Total |
|
|
Loss from dedesignation amortized from accumulated OCI into income |
|
$ |
- |
|
|
$ |
(1,184 |
) |
|
$ |
(1,184 |
) |
|
$ |
- |
|
|
$ |
(117 |
) |
|
$ |
(117 |
) |
|
Loss recognized in income |
|
|
- |
|
|
|
(7,092 |
) |
|
|
(7,092 |
) |
|
|
- |
|
|
|
(21,890 |
) |
|
|
(21,890 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit risk assessment for commodity and interest rate swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
| |
|
|
|
|
|
|
|
|
|
June 30, 2009 |
|
|
|
June 30, 2008 |
|
|
|
June 30, 2009 |
|
|
June 30, 2008 |
|
|
Gain recognized in income |
|
|
|
|
|
|
|
|
|
$ |
1,430 |
|
|
$ |
948 |
|
|
$ |
950 |
|
|
$ |
948 |
|
6. Long-term Debt, net
Obligations in the form of senior notes and borrowings under the credit facilities are as follows.
| |
|
|
|
|
|
|
| |
|
June 30, 2009 |
|
|
December 31, 2008 |
|
| |
|
(in thousands) |
|
| |
|
|
|
|
|
|
|
Senior notes |
|
$ |
593,906 |
|
|
$ |
357,500 |
|
|
Revolving loans |
|
|
591,479 |
|
|
|
768,729 |
|
|
Total |
|
|
1,185,385 |
|
|
|
1,126,229 |
|
|
Less: current portion |
|
|
- |
|
|
|
- |
|
|
Long-term debt |
|
$ |
1,185,385 |
|
|
$ |
1,126,229 |
|
| |
|
|
|
|
|
|
|
|
|
Availability under revolving credit facility: |
|
|
|
|
|
|
|
|
|
Total credit facility limit |
|
$ |
900,000 |
|
|
$ |
900,000 |
|
|
Unfunded Lehman commitments |
|
|
(7,030 |
) |
|
|
(8,646 |
) |
|
Revolving loans |
|
|
(591,479 |
) |
|
|
(768,729 |
) |
|
Letters of credit |
|
|
(16,257 |
) |
|
|
(16,257 |
) |
|
Total available |
|
$ |
285,234 |
|
|
$ |
106,368 |
|
On May 20, 2009, the Partnership and Finance Corp. issued $250,000,000 senior notes in a private placement that mature on June 1, 2016. The senior notes bear interest at 9.375 percent with interest payable semiannually on June 1 and December 1. The proceeds were used to partially repay revolving loans under the Partnership’s
credit facility.
The Partnership has a commitment to register the 9.375 percent senior notes due 2016 by May 2010. Failure to do so would result in a registration default. For the first 90 day period beyond the registration default, the Partnership would be required to pay .25 percent of the face amount of the notes as liquidated damages
until the default is cured. The rate of liquidated damages would increase by an additional .25 percent for each subsequent 90 day period of the registration default, with a maximum amount of liquidated damages of 1.0 percent per year. The Partnership’s management expects to be able to register the notes in a timely manner, and accordingly has not recognized a liability for this registration payment arrangement.
At any time before June 1, 2012, up to 35 percent of the senior notes can be redeemed at a price of 109.375 percent plus accrued interest and liquidated damages. On or after June 1, 2013, all or part of the senior notes can be redeemed at a price of 100 percent plus accrued interest and liquidated damages. At any time
prior to June 1, 2013, the Partnership may also redeem all or part of the notes at a price equal to 100 percent of the principal amount of notes redeemed plus accrued interest, liquidated damages, and the applicable premium, which equals to the greater of (1) 1 percent of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at June 1, 2013 plus (ii) all required interest payments due on the note through June 1, 2013, computed
using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over the principal amount of the note.
Upon change of control each note holder will be entitled to require the Partnership to purchase all or a portion of its notes at a purchase price of 101 percent plus accrued interest and liquidated damages. The senior notes contain various covenants that limit, among other things, the Partnership’s ability and the ability
of certain of its subsidiaries to:
|
· |
incur additional indebtedness; |
|
· |
pay distributions on, or repurchase or redeem equity interests; |
|
· |
make certain investments; |
|
· |
incur liens; |
|
· |
enter into certain types of transactions with affiliates; and |
|
· |
sell assets, consolidate or merge with or into other companies. |
The senior notes are jointly and severally guaranteed by all of the Partnership’s current consolidated subsidiaries, other than Finance Corp., and by certain of its future subsidiaries. The senior notes and the guarantees are unsecured and rank equally with all of the Partnership’s and the guarantors’ existing
and future unsubordinated obligations. The senior notes and the guarantees will be senior in right of payment to any of the Partnership’s and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The senior notes and the guarantees will be effectively subordinated to the Partnership’s and the guarantors’ secured obligations, including the Partnership’s Credit Facility, to the extent of the
value of the assets securing such obligations.
Finance Corp. has no operations and will not have revenue other than as may be incidental as co-issuer of the senior notes. Since the Partnership has no independent operations, the guarantees are fully unconditional and joint and several of its subsidiaries, except certain wholly owned subsidiaries, the Partnership has not included
condensed consolidated financial information of guarantors of the senior notes.
The unamortized balance of the discount on the Partnership’s senior notes due 2016 is as follows.
| |
|
June 30, 2009 |
|
|
December 31, 2008 |
|
| |
|
(in thousands) |
|
|
Principal amount |
|
$ |
250,000 |
|
|
$ |
- |
|
|
Less: unamortized discount |
|
|
(13,594 |
) |
|
|
- |
|
| |
|
$ |
236,406 |
|
|
$ |
- |
|
On March 17, 2009, RGS amended its credit agreement to authorize the contribution of RIGS to a joint venture (HPC) and allow for future investment up to $135,000,000 in a joint venture. The amendment imposed additional financial restrictions that limit the ratio of senior secured indebtedness to EBITDA. The alternate
base rate used to calculate interest on base rate loans will be calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.50 percent and an adjusted one-month LIBOR rate plus 1.50 percent. The applicable margin shall range from 1.50 percent to 2.25 percent for base rate loans, 2.50 percent to 3.25 percent for Eurodollar loans, and commitment fees will range from 0.375 percent to 0.500 percent.
On July 24, 2009, RGS further amended its credit agreement to allow for a $25,000,000 working capital facility for the RIGS Haynesville Joint Venture.
GECC Credit Facility. On February 26, 2009, the Partnership entered into a $45,000,000 unsecured revolving credit agreement with GECC. The proceeds of the GECC Credit Facility were available for expenditures made in connection with the Haynesville Expansion Project
prior to the effectiveness of the above March 17, 2009 amendment. The commitments under the Revolving Credit Facility terminated on March 17, 2009. The Partnership paid a commitment fee of $2,718,000 to GECC related to this GECC Credit Facility, which was recorded as a decrease to gain on asset sales, net.
On September 15, 2008, Lehman filed a petition in the United States Bankruptcy Court seeking relief under chapter 11 of the United States Bankruptcy Code. As of June 30, 2009, the Partnership borrowed all but $7,030,000 of the amount committed by Lehman under the Credit Facility. Lehman has declined requests to honor
its remaining commitment, effectively reducing the total size of the Credit Facility’s capacity to $892,970,000. Further, if the Partnership makes repayments of loans against the revolving facility which were, in part, funded by Lehman, the amounts funded by Lehman may not be reborrowed.
The outstanding balance of revolving debt under the credit facility bears interest at LIBOR plus a margin or Alternate Base Rate (equivalent to the U.S prime rate lending rate) plus a margin or a combination of both. The weighted average interest rates for the revolving loans and senior notes, including interest rate swap settlements,
commitment fees, and amortization of debt issuance costs were 5.94 percent and 6.49 percent for the six months ended June 30, 2009 and 2008, respectively, and 6.69 percent and 6.12 percent for the three months ended June 30, 2009 and 2008, respectively. The senior notes pay fixed rate of interest with a weighted average rate of 8.787 percent.
7. Commitments and Contingencies
Legal. The Partnership is involved in various claims and lawsuits incidental to its business. These claims and lawsuits in the aggregate should not have a material adverse effect on the Partnership’s business, financial condition, results of operations or
cash flows.
Escrow Payable. At June 30, 2009, $1,510,000 remained in escrow pending the completion by El Paso of environmental remediation projects pursuant to the purchase and sale agreement (“El Paso PSA”) related to assets in north Louisiana and the mid-continent area. In
the El Paso PSA, El Paso indemnified the predecessor of our operating partnership, RGS, against losses arising from pre-closing and known environmental liabilities subject to a limit of $84,000,000 and certain deductible limits. Upon completion of a Phase II environmental study, the Partnership notified El Paso of remediation obligations amounting to $1,800,000 with respect to known environmental matters and $3,600,000 with respect to pre-closing environmental liabilities. This escrow amount
will be further reduced under a specified schedule as El Paso completes its cleanup obligations and the remainder will be released upon completion.
Environmental. A Phase I environmental study was performed on certain assets located in west Texas in connection with the pre-acquisition due diligence process in 2004. Most of the identified environmental contamination had either been remediated or was being remediated
by the previous owners or operators of the properties. The aggregate potential environmental remediation costs at specific locations were estimated to range from $1,900,000 to $3,100,000. No governmental agency has required the Partnership to undertake these remediation efforts. Management believes that the likelihood that it will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, the Partnership acquired an
environmental pollution liability insurance policy in connection with the acquisition to cover any undetected or unknown pollution discovered in the future. The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10,000,000 limit subject to certain deductibles. No claims have been made against the Partnership or under the policy.
TCEQ Notice of Enforcement. On February 15, 2008, the TCEQ issued a NOE concerning one of the Partnership’s processing plants located in McMullen County, Texas (the “Plant”). The NOE alleges that, between March 9, 2006, and May 8, 2007, the Plant
experienced 15 emission events of various durations from four hours to 41 days, which were not reported to TCEQ and other agencies within 24 hours of occurrence. On April 3, 2008, TCEQ presented the Partnership with a written offer to settle the allegation in the NOE in exchange for payment of an administrative penalty of $480,000, and it later reduced its settlement demand to $360,000 in July 2008. The Partnership was unable to settle this matter on a satisfactory basis and the TCEQ has
referred the matter to its litigation division for further administrative proceedings.
Keyes Litigation. In August 2008, Keyes Helium Company, LLC (“Keyes”) filed suit against Regency Gas Services LP, the Partnership, and the General Partner. Keyes entered into an output contract with the Partnership’s predecessor in 1996 under which
it purchased all of the helium produced at the Lakin processing plant in southwest Kansas. In September 2004, the Partnership decided to shut down its Lakin plant and contract with a third party for the processing of volumes processed at Lakin, as a result of which the Partnership no longer delivered any helium to Keyes. As a result, Keyes alleges it is entitled to an unspecified amount of damages for the costs of covering its purchases of helium. Discovery is expected to end
in September 2009 and trial is scheduled for December 2009.
Kansas State Severance Tax. In August 2008, a customer began remitting severance tax to the state of Kansas based on the value of condensate purchased from one of the Partnership’s Mid-Continent gathering fields and deducting the tax from its payments to the Partnership. The
Kansas Department of Revenue advised the customer that it was appropriate to remit such taxes and withhold the taxes from its payments to the Partnership, absent an order or legal opinion from the Kansas Department of Revenue stating otherwise. The Partnership has requested a determination and refund from the Kansas Department of Revenue regarding the matter since severance taxes were already paid on the gas from which the condensate is collected and no additional tax is due. The Kansas
Department of Revenue has initiated an audit of the Partnership’s condensate sales in Kansas. If the Kansas Department of Revenue determines that the condensate sales are taxable, then the Partnership may be subject to additional taxes, interest and possibly penalties for past and future condensate sales.
Caddo Gas Gathering LLC v. Regency Intrastate Gas LLC. Caddo Gas Gathering LLC (“Caddo Gas”) claims that RIGS breached a 1988 natural gas transportation agreement (the “Transportation Agreement”). Caddo Gas alleges that the Transportation
Agreement requires RIGS to take receipt of gas at any receipt point on the “Regency Gas System” and redeliver that gas for $0.05 per MMbtu. It further alleges that RIGS’ obligation to provide transportation to Caddo Gas is unconditional and that RIGS breached the Transportation Agreement when it refused to let Caddo Gas access a fully-subscribed receipt point interconnect at the Centerpoint Energy Sligo Plant (“Sligo Point”), but offered to install a new interconnect at
Caddo Gas’ cost. RIGS filed an answer denying that Caddo Gas was entitled to access the Regency Gas System through the Sligo Point and denying that its actions constituted a breach of the Transportation Agreement. No trial date has been set.
Remediation of Groundwater Contamination at Calhoun and Dubach Plants. RFS currently owns the Dubach and Calhoun gas processing plants in north Louisiana (the “Plants”). The Plants each have groundwater contamination as result of historical operations. At
the time that RFS acquired the Plants from El Paso, Kerr-McGee Corporation (Kerr-McGee) was performing remediation of the groundwater contamination, because the Plants were once owned by Kerr-McGee and when Kerr-McGee sold the Plants to a predecessor of El Paso in 1988, Kerr-McGee retained liability for any environmental contamination at the Plants. In 2005, Kerr-McGee created and spun off Tronox and Tronox allegedly assumed certain Kerr-McGee’s environmental remediation obligations (including
its obligation to perform remediation at the Plants) prior to the acquisition of Kerr-McGee by Anadarko Petroleum Corporation. In January 2009, Tronox filed for Chapter 11 bankruptcy protection. RFS will file a claim in the bankruptcy proceeding relating to the environmental remediation work at the Plants.
8. Related Party Transactions
The employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services are employees of the General Partner. Pursuant to the Partnership Agreement, our General Partner receives a monthly reimbursement for all direct and indirect expenses incurred on behalf of the Partnership. Reimbursements
of $8,591,000, $16,209,000, $8,433,000, and $15,321,000 were recorded in the Partnership’s financial statements during the three and six months ended June 30, 2009 and 2008, respectively, as operation and maintenance expenses or general and administrative expenses, as appropriate.
In conjunction with distributions by the Partnership to its limited and general partner interests, during the six months ended June 30, 2009, GE EFS received cash distributions of $12,181,000 and certain members of management received cash distributions of $768,000.
The Partnership’s contract compression segment provides contract compression services to HPC. Under a Master Services Agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. Under this agreement the Partnership will receive $500,000 monthly as
a partial reimbursement of its general and administrative costs. The amount is recorded as fee revenue in the Partnership’s corporate and other segment. Additionally, the Partnership incurs expenditures on behalf of HPC and these amounts are billed to HPC on a monthly basis. As of and for the three and six months ended June 30, 2009, the Partnership’s related party receivables, related party payables, related party revenues and related party cost of sales were primarily
a result of the transactions described above.
9. Segment Information
With the completion of the Contribution Agreement, the Partnership’s management realigned the composition of its segments. Accordingly, the Partnership has restated the items of segment information for earlier periods to reflect this new alignment.
The Partnership has three principal reportable segments: (a) gathering and processing, (b) transportation, and (c) contract compression. Gathering and processing involves collecting raw natural gas from producer wells and transporting it to treating plants where water and other impurities such as hydrogen sulfide and carbon dioxide
are removed. Treated gas is then processed to remove the natural gas liquids. The treated and processed natural gas is then transported to market separately from the natural gas liquids. Revenues and the associated cost of sales from the gathering and processing segment directly expose the Partnership to commodity price risk, which is managed through derivative contracts and other measures. The Partnership aggregates the results of its gathering and processing activities
across five geographic regions into a single reporting segment. The Partnership, through its producer services function, primarily purchases natural gas from producers at gathering systems and plants connected to its pipeline systems and sells this gas at downstream outlets.
Following the contribution of RIGS to HPC, the transportation segment consists exclusively of the Partnership’s 38 percent interest in HPC, for which equity method accounting applies. Prior periods have been restated to reflect the Partnership’s then wholly owned subsidiary of Regency Intrastate Gas LLC as the exclusive
reporting unit within this segment. The transportation segment uses pipelines to transport natural gas from receipt points on its system to interconnections with other pipelines, storage facilities or end-use markets. RIGS performs transportation services for shipping customers under firm or interruptible arrangements. In either case, revenues are primarily fee based and involve minimal direct exposure to commodity price fluctuations. The north Louisiana intrastate
pipeline operated by this segment serves the Partnership’s gathering and processing facilities in the same area and those transactions create a portion of the intersegment revenues shown in the table below.
The contract compression segment provides customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput, and cash flow. The Partnership’s integrated solutions include a comprehensive assessment of a customer’s natural gas contract compression needs and the
design and installation of a compression system that addresses those particular needs. The Partnership is responsible for the installation and ongoing operation, service, and repair of its compression units, which are modified as necessary to adapt to customers’ changing operating conditions. The contract compression segment also provides services to certain operations in the gathering and processing segment, creating a portion of the intersegment revenues shown in the table below.
The corporate and others segment comprises regulated entities and the Partnership’s corporate offices. Revenues in this segment include the collection of the partial reimbursement of general and administrative costs from HPC.
Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses. Segment margin, for the gathering and processing and for the transportation segments, is defined as total revenues, including service fees, less
cost of sales. In the contract compression segment, segment margin is defined as revenues minus direct costs, which primarily consist of compressor repairs. Management believes segment margin is an important measure because it directly relates to volume, commodity price changes and revenue generating horsepower. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations. Direct labor, insurance, property
taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin.
Results for each income statement period, together with amounts related to balance sheets for each segment are shown below.
| |
|
Gathering and Processing |
|
|
Transportation |
|
|
Contract Compression |
|
|
Corporate and Others |
|
|
Eliminations |
|
|
Total |
|
| |
|
(in thousands) |
|
|
External Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended June 30, 2009 |
|
$ |
209,939 |
|
|
$ |
1,531 |
|
|
$ |
39,011 |
|
|
$ |
3,061 |
|
|
$ |
- |
|
|
$ |
253,542 |
|
|
For the three months ended June 30, 2008 |
|
|
503,466 |
|
|
|
9,975 |
|
|
|
32,587 |
|
|
|
677 |
|
|
|
- |
|
|
|
546,705 |
|
|
For the six months ended June 30, 2009 |
|
|
453,093 |
|
|
|
9,075 |
|
|
|
77,499 |
|
|
|
3,853 |
|
|
|
- |
|
|
|
543,520 |
|
|
For the six months ended June 30, 2008 |
|
|
872,535 |
|
|
|
20,209 |
|
|
|
57,854 |
|
|
|
1,342 |
|
|
|
- |
|
|
|
951,940 |
|
|
Intersegment Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended June 30, 2009 |
|
|
(6,745 |
) |
|
|
(128 |
) |
|
|
975 |
|
|
|
40 |
|
|
|
5,858 |
|
|
|
- |
|
|
For the three months ended June 30, 2008 |
|
|
11,353 |
|
|
|
2,996 |
|
|
|
164 |
|
|
|
87 |
|
|
|
(14,600 |
) |
|
|
- |
|
|
For the six months ended June 30, 2009 |
|
|
(8,755 |
) |
|
|
4,936 |
|
|
|
1,785 |
|
|
|
144 |
|
|
|
1,890 |
|
|
|
- |
|
|
For the six months ended June 30, 2008 |
|
|
15,546 |
|
|
|
6,360 |
|
|
|
282 |
|
|
|
178 |
|
|
|
(22,366 |
) |
|
|
- |
|
|
Cost of Sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended June 30, 2009 |
|
|
144,816 |