UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2011
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 000-51757
REGENCY ENERGY PARTNERS LP
(Exact name of registrant as specified in its charter)
DELAWARE | 16-1731691 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) | |
2001 BRYAN STREET, SUITE 3700 DALLAS, TX |
75201 | |
(Address of principal executive offices) | (Zip Code) |
(214) 750-1771
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and small reporting company in Rule 12b-2 of the Exchange Act.
Large accelerated filer | x | Accelerated filer | ¨ | |||
Non-accelerated filer | ¨ (Do not check if a smaller reporting company) | Smaller reporting company | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The issuer had 145,843,942 common units outstanding as of July 29, 2011.
INDEX
Regency Energy Partners LP
ITEM 1. |
||||||
2 | ||||||
3 | ||||||
Condensed Consolidated Statements of Comprehensive Income (Loss) |
5 | |||||
6 | ||||||
Condensed Consolidated Statement of Partners Capital and Noncontrolling Interest |
7 | |||||
8 | ||||||
ITEM 2. |
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 24 | ||||
ITEM 3. |
35 | |||||
ITEM 4. |
36 | |||||
ITEM 1. |
37 | |||||
ITEM 1A. |
37 | |||||
ITEM 2. |
37 | |||||
ITEM 3. |
37 | |||||
ITEM 4. |
37 | |||||
ITEM 5. |
37 | |||||
ITEM 6. |
38 | |||||
39 |
i
Introductory Statement
References in this report to the Partnership, we, our, us and similar terms, when used in an historical context, refer to Regency Energy Partners LP and its subsidiaries. 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:
Name |
Definition or Description | |
/d | Per day | |
AOCI | Accumulated Other Comprehensive Income | |
Bbls | Barrels | |
Bcf | One billion cubic feet | |
BTU | A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit | |
ETC | Energy Transfer Company, the name assumed by La Grange Acquisition, L.P. for conducting business and shared services, a wholly-owned subsidiary of ETP | |
ETE | Energy Transfer Equity, L.P. | |
ETE GP | ETE GP Acquirer LLC | |
ETP | Energy Transfer Partners, L.P. | |
Finance Corp. | Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership | |
GAAP | Accounting principles generally accepted in the United States of America | |
GE EFS | General Electric Energy Financial Services, combined with Regency GP Acquirer LP and Regency LP | |
General Partner | 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 partnerships | |
GPM | Gallons per minute | |
GP Seller | Regency GP Acquirer, L.P. | |
HPC | RIGS Haynesville Partnership Co., a general partnership in which the Partnership owns a 49.99% interest and its 100% owned subsidiary, Regency Intrastate Gas LP | |
IDRs | Incentive Distribution Rights | |
IRS | Internal Revenue Service | |
LDH | LDH Energy Asset Holdings LLC | |
LIBOR | London Interbank Offered Rate | |
Lone Star | Lone Star NGL LLC, a joint venture that is 70% owned by ETP and 30% owned by the Partnership | |
LTIP | Long-Term Incentive Plan | |
MEP | Midcontinent Express Pipeline LLC, a joint venture in which the Partnership owns a 49.9% interest | |
MMbtu | One million BTUs | |
NGLs | Natural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline | |
NYMEX | New York Mercantile Exchange | |
Partnership | Regency Energy Partners LP | |
RGS | Regency Gas Services LP, a wholly-owned subsidiary of the Partnership | |
RIGS | Regency Intrastate Gas System | |
SEC | Securities and Exchange Commission | |
Series A Preferred Units | Series A convertible redeemable preferred units | |
Services Co. | ETE Services Company, LLC | |
WTI | West Texas Intermediate Crude |
ii
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, as amended (the Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). 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:
| volatility in the price of oil, natural gas, and natural gas liquids; |
| declines in the credit markets and the availability of credit for us as well as for producers connected to our pipelines and our gathering and processing facilities, and for our customers of contract compression and contract treating businesses; |
| the level of creditworthiness of, and performance by, our counterparties and customers; |
| our access to capital to fund organic growth projects and acquisitions, and our ability to obtain debt or equity financing on satisfactory terms; |
| our use of derivative financial instruments to hedge commodity and interest rate risks; |
| the amount of collateral required to be posted from time-to-time in our transactions; |
| changes in commodity prices, interest rates and demand for our services; |
| changes in laws and regulations impacting the midstream sector of the natural gas industry, including those that relate to climate change and environmental protection; |
| weather and other natural phenomena; |
| industry changes including the impact of consolidations and changes in competition; |
| regulation of transportation rates on our natural gas pipelines; |
| our ability to obtain indemnification cleanup liabilities and to clean up any hazardous materials release on satisfactory terms; |
| our ability to obtain required approvals for construction or modernization of our facilities and the timing of production from such facilities; and |
| 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, 2010 Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.
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.
iii
PART I FINANCIAL INFORMATION
Item 1. | Financial Statements |
As disclosed in Note 1, on May 26, 2010, GP Seller sold all of the outstanding membership interests of the Partnerships General Partner to ETE, effecting a change in control of the Partnership. In connection with this transaction, the Partnerships assets and liabilities were adjusted to fair value at the acquisition date by application of push-down accounting. As a result, the Partnerships unaudited condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (1) the period prior to the acquisition date (May 26, 2010), identified as Predecessor and (2) the period from May 26, 2010 forward, identified as Successor.
1
Condensed Consolidated Balance Sheets
(in thousands)
(unaudited)
June 30, 2011 |
December 31, 2010 |
|||||||
ASSETS | ||||||||
Current Assets: |
||||||||
Cash and cash equivalents |
$ | 3,105 | $ | 9,400 | ||||
Trade accounts receivable, net of allowance of $465 and $297 |
36,740 | 35,212 | ||||||
Accrued revenues |
85,195 | 74,017 | ||||||
Related party receivables |
34,587 | 32,342 | ||||||
Derivative assets |
1,075 | 2,650 | ||||||
Other current assets |
8,772 | 7,384 | ||||||
|
|
|
|
|||||
Total current assets |
169,474 | 161,005 | ||||||
Property, Plant and Equipment: |
||||||||
Gathering and transmission systems |
591,915 | 543,286 | ||||||
Compression equipment |
825,944 | 812,428 | ||||||
Gas plants and buildings |
178,134 | 185,741 | ||||||
Other property, plant and equipment |
122,276 | 81,295 | ||||||
Construction-in-progress |
154,739 | 97,439 | ||||||
|
|
|
|
|||||
Total property, plant and equipment |
1,873,008 | 1,720,189 | ||||||
Less accumulated depreciation |
(123,755 | ) | (59,971 | ) | ||||
|
|
|
|
|||||
Property, plant and equipment, net |
1,749,253 | 1,660,218 | ||||||
Other Assets: |
||||||||
Investment in unconsolidated affiliates |
1,920,412 | 1,351,256 | ||||||
Long-term derivative assets |
366 | 23 | ||||||
Other, net of accumulated amortization of debt issuance costs of $6,621 and $3,326 |
43,316 | 37,758 | ||||||
|
|
|
|
|||||
Total other assets |
1,964,094 | 1,389,037 | ||||||
Intangible Assets and Goodwill: |
||||||||
Intangible assets, net of accumulated amortization of $30,220 and $15,584 |
755,519 | 770,155 | ||||||
Goodwill |
789,789 | 789,789 | ||||||
|
|
|
|
|||||
Total intangible assets and goodwill |
1,545,308 | 1,559,944 | ||||||
|
|
|
|
|||||
TOTAL ASSETS |
$ | 5,428,129 | $ | 4,770,204 | ||||
|
|
|
|
|||||
LIABILITIES AND PARTNERS CAPITAL AND NONCONTROLLING INTEREST | ||||||||
Current Liabilities: |
||||||||
Trade accounts payable |
$ | 37,035 | $ | 50,208 | ||||
Accrued cost of gas and liquids |
81,906 | 80,756 | ||||||
Related party payables |
37,185 | 3,338 | ||||||
Deferred revenues, including related party amounts of $41 and $8,765 |
17,348 | 25,257 | ||||||
Derivative liabilities |
20,679 | 13,172 | ||||||
Other current liabilities |
30,280 | 23,419 | ||||||
|
|
|
|
|||||
Total current liabilities |
224,433 | 196,150 | ||||||
Long-term derivative liabilities |
53,033 | 61,127 | ||||||
Other long-term liabilities |
6,046 | 6,521 | ||||||
Long-term debt, net |
1,685,613 | 1,141,061 | ||||||
Commitments and contingencies |
||||||||
Series A Preferred Units, redemption amount of $84,549 and $83,891 |
71,040 | 70,943 | ||||||
Partners capital and noncontrolling interest: |
||||||||
Common units |
3,042,153 | 2,940,732 | ||||||
General partner interest |
331,166 | 333,077 | ||||||
Accumulated other comprehensive loss |
(17,571 | ) | (11,099 | ) | ||||
|
|
|
|
|||||
Total partners capital |
3,355,748 | 3,262,710 | ||||||
Noncontrolling interest |
32,216 | 31,692 | ||||||
|
|
|
|
|||||
Total partners capital and noncontrolling interest |
3,387,964 | 3,294,402 | ||||||
|
|
|
|
|||||
TOTAL LIABILITIES AND PARTNERS CAPITAL AND NONCONTROLLING INTEREST |
$ | 5,428,129 | $ | 4,770,204 | ||||
|
|
|
|
See accompanying notes to condensed consolidated financial statements
2
Condensed Consolidated Statements of Operations
(in thousands except unit data and per unit data)
(unaudited)
Successor | Predecessor | |||||||||||||
Three Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from April 1, 2010 to May 25, 2010 |
||||||||||||
REVENUES: |
||||||||||||||
Gas sales, including related party amounts of $6,161, $447 and $0 |
$ | 132,800 | $ | 47,241 | $ | 87,193 | ||||||||
NGL sales, including related party amounts of $77,048, $18,054 and $0 |
138,088 | 26,040 | 62,997 | |||||||||||
Gathering, transportation and other fees, including related party amounts of $5,254, $2,086 and $3,680 |
81,817 | 22,571 | 45,041 | |||||||||||
Net realized and unrealized (loss) gain from derivatives |
(7,542 | ) | (130 | ) | 223 | |||||||||
Other, including related party amounts of $2,924, $0 and $0 |
11,335 | 1,258 | 4,811 | |||||||||||
|
|
|
|
|
|
|||||||||
Total revenues |
356,498 | 96,980 | 200,265 | |||||||||||
OPERATING COSTS AND EXPENSES: |
||||||||||||||
Cost of sales, including related party amounts of $7,807, $2,281 and $3,198 |
259,475 | 70,174 | 140,507 | |||||||||||
Operation and maintenance |
33,996 | 10,402 | 19,315 | |||||||||||
General and administrative, including related party amounts of $4,224, $833 and $0 |
17,551 | 7,104 | 21,809 | |||||||||||
Loss on asset sales, net |
153 | 10 | 19 | |||||||||||
Depreciation and amortization |
40,503 | 10,545 | 16,889 | |||||||||||
|
|
|
|
|
|
|||||||||
Total operating costs and expenses |
351,678 | 98,235 | 198,539 | |||||||||||
OPERATING INCOME (LOSS): |
4,820 | (1,255 | ) | 1,726 | ||||||||||
Income from unconsolidated affiliates |
32,167 | 8,121 | 7,959 | |||||||||||
Interest expense, net |
(24,689 | ) | (8,081 | ) | (14,059 | ) | ||||||||
Other income and deductions, net |
2,641 | (3,521 | ) | (624 | ) | |||||||||
|
|
|
|
|
|
|||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
14,939 | (4,736 | ) | (4,998 | ) | |||||||||
Income tax expense |
102 | 245 | 83 | |||||||||||
|
|
|
|
|
|
|||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS |
$ | 14,837 | $ | (4,981 | ) | $ | (5,081 | ) | ||||||
DISCONTINUED OPERATIONS: |
||||||||||||||
Net income from operations of east Texas assets |
| 86 | 585 | |||||||||||
|
|
|
|
|
|
|||||||||
NET INCOME (LOSS) |
$ | 14,837 | $ | (4,895 | ) | $ | (4,496 | ) | ||||||
Net income attributable to noncontrolling interest |
(293 | ) | (29 | ) | (244 | ) | ||||||||
|
|
|
|
|
|
|||||||||
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP |
$ | 14,544 | $ | (4,924 | ) | $ | (4,740 | ) | ||||||
|
|
|
|
|
|
|||||||||
Amounts attributable to Series A Preferred Units |
1,995 | 668 | 1,335 | |||||||||||
General partners interest, including IDRs |
1,550 | 803 | | |||||||||||
|
|
|
|
|
|
|||||||||
Limited partners interest in net income (loss) |
$ | 10,999 | $ | (6,395 | ) | $ | (6,075 | ) | ||||||
|
|
|
|
|
|
|||||||||
Income (loss) from continuing operations per common unit: |
||||||||||||||
Amount allocated to common units |
$ | 10,999 | $ | (6,479 | ) | $ | (6,660 | ) | ||||||
Weighted average number of common units outstanding |
142,937,163 | 119,600,652 | 92,832,219 | |||||||||||
Basic income (loss) from continuing operations per common unit |
$ | 0.08 | $ | (0.05 | ) | $ | (0.07 | ) | ||||||
Diluted income (loss) from continuing operations per common unit |
$ | 0.07 | $ | (0.05 | ) | $ | (0.07 | ) | ||||||
Distributions per unit |
$ | 0.45 | $ | 0.445 | $ | | ||||||||
Basic and diluted income from discontinued operations per common unit |
$ | | $ | | $ | 0.01 | ||||||||
Basic and diluted net income (loss) per common unit: |
||||||||||||||
Amount allocated to common units |
$ | 10,999 | $ | (6,395 | ) | $ | (6,075 | ) | ||||||
Basic net income (loss) per common unit |
$ | 0.08 | $ | (0.05 | ) | $ | (0.07 | ) | ||||||
Diluted net income (loss) per common unit |
$ | 0.07 | $ | (0.05 | ) | $ | (0.07 | ) |
See accompanying notes to condensed consolidated financial statements
3
Regency Energy Partners LP
Condensed Consolidated Statements of Operations
(in thousands except unit data and per unit data)
(unaudited)
Successor | Predecessor | |||||||||||||
Six Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from January 1, 2010 to May 25, 2010 |
||||||||||||
REVENUES: |
||||||||||||||
Gas sales, including related party amounts of $11,639, $447 and $0 |
$ | 242,887 | $ | 47,241 | $ | 228,097 | ||||||||
NGL sales, including related party amounts of $150,041, $18,054 and $0 |
256,339 | 26,040 | 152,803 | |||||||||||
Gathering, transportation and other fees, including related party amounts of $11,470, $2,086 and $12,200 |
163,653 | 22,571 | 114,526 | |||||||||||
Net realized and unrealized loss from derivatives |
(9,256 | ) | (130 | ) | (716 | ) | ||||||||
Other, including related party amounts of $4,790, $0 and $0 |
20,127 | 1,258 | 10,340 | |||||||||||
|
|
|
|
|
|
|||||||||
Total revenues |
673,750 | 96,980 | 505,050 | |||||||||||
OPERATING COSTS AND EXPENSES: |
||||||||||||||
Cost of sales, including related party amounts of $11,021, $2,281 and $6,564 |
475,736 | 70,174 | 357,778 | |||||||||||
Operation and maintenance |
67,556 | 10,402 | 47,842 | |||||||||||
General and administrative, including related party amounts of $8,129, $833 and $0 |
36,660 | 7,104 | 37,212 | |||||||||||
Loss on asset sales, net |
181 | 10 | 303 | |||||||||||
Depreciation and amortization |
80,739 | 10,545 | 41,784 | |||||||||||
|
|
|
|
|
|
|||||||||
Total operating costs and expenses |
660,872 | 98,235 | 484,919 | |||||||||||
OPERATING INCOME (LOSS): |
12,878 | (1,255 | ) | 20,131 | ||||||||||
Income from unconsolidated affiliates |
55,975 | 8,121 | 15,872 | |||||||||||
Interest expense, net |
(44,696 | ) | (8,081 | ) | (34,541 | ) | ||||||||
Loss on debt refinancing, net |
| | (1,780 | ) | ||||||||||
Other income and deductions, net |
5,055 | (3,521 | ) | (3,897 | ) | |||||||||
|
|
|
|
|
|
|||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
29,212 | (4,736 | ) | (4,215 | ) | |||||||||
Income tax expense |
70 | 245 | 404 | |||||||||||
|
|
|
|
|
|
|||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS |
$ | 29,142 | $ | (4,981 | ) | $ | (4,619 | ) | ||||||
DISCONTINUED OPERATIONS: |
||||||||||||||
Net income (loss) from operations of east Texas assets |
| 86 | (327 | ) | ||||||||||
|
|
|
|
|
|
|||||||||
NET INCOME (LOSS) |
$ | 29,142 | $ | (4,895 | ) | $ | (4,946 | ) | ||||||
Net income attributable to noncontrolling interest |
(524 | ) | (29 | ) | (406 | ) | ||||||||
|
|
|
|
|
|
|||||||||
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP |
$ | 28,618 | $ | (4,924 | ) | $ | (5,352 | ) | ||||||
|
|
|
|
|
|
|||||||||
Amounts attributable to Series A Preferred Units |
3,988 | 668 | 3,336 | |||||||||||
General partners interest, including IDRs |
2,842 | 803 | 662 | |||||||||||
Amount allocated to non-vested common units |
| | (79 | ) | ||||||||||
|
|
|
|
|
|
|||||||||
Limited partners interest in net income (loss) |
$ | 21,788 | $ | (6,395 | ) | $ | (9,271 | ) | ||||||
|
|
|
|
|
|
|||||||||
Income (loss) from continuing operations per common unit: |
||||||||||||||
Amount allocated to common units |
$ | 21,788 | $ | (6,479 | ) | $ | (8,966 | ) | ||||||
Weighted average number of common units outstanding |
140,135,219 | 119,600,652 | 92,788,319 | |||||||||||
Basic income (loss) from continuing operations per common unit |
$ | 0.16 | $ | (0.05 | ) | $ | (0.10 | ) | ||||||
Diluted income (loss) from continuing operations per common unit |
$ | 0.14 | $ | (0.05 | ) | $ | (0.10 | ) | ||||||
Distributions per unit |
$ | 0.895 | $ | 0.445 | $ | 0.445 | ||||||||
Basic and diluted income from discontinued operations per common unit |
$ | | $ | | $ | | ||||||||
Basic and diluted net income (loss) per common unit: |
||||||||||||||
Amount allocated to common units |
$ | 21,788 | $ | (6,395 | ) | $ | (9,271 | ) | ||||||
Basic net income (loss) per common unit |
$ | 0.16 | $ | (0.05 | ) | $ | (0.10 | ) | ||||||
Diluted net income (loss) per common unit |
$ | 0.14 | $ | (0.05 | ) | $ | (0.10 | ) |
See accompanying notes to condensed consolidated financial statements
4
Condensed Consolidated Statements of Comprehensive Income (Loss)
(in thousands)
(unaudited)
Successor | Predecessor | |||||||||||||
Three Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from April 1, 2010 to May 25, 2010 |
||||||||||||
Net income (loss) |
$ | 14,837 | $ | (4,895 | ) | $ | (4,496 | ) | ||||||
Net cash flow hedge amounts reclassified to earnings |
5,565 | | (512 | ) | ||||||||||
Change in fair value of cash flow hedges |
1,530 | | 8,649 | |||||||||||
|
|
|
|
|
|
|||||||||
Comprehensive income (loss) |
21,932 | (4,895 | ) | 3,641 | ||||||||||
Comprehensive income attributable to noncontrolling interest |
293 | 29 | 244 | |||||||||||
|
|
|
|
|
|
|||||||||
Comprehensive income (loss) attributable to Regency Energy Partners LP |
$ | 21,639 | $ | (4,924 | ) | $ | 3,397 | |||||||
|
|
|
|
|
|
|||||||||
Successor | Predecessor | |||||||||||||
Six Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from January 1, 2010 to May 25, 2010 |
||||||||||||
Net income (loss) |
$ | 29,142 | $ | (4,895 | ) | $ | (4,946 | ) | ||||||
Net cash flow hedge amounts reclassified to earnings |
8,994 | | 2,145 | |||||||||||
Net change in fair value of cash flow hedges |
(15,466 | ) | | 18,486 | ||||||||||
|
|
|
|
|
|
|||||||||
Comprehensive income (loss) |
22,670 | (4,895 | ) | 15,685 | ||||||||||
Comprehensive income attributable to noncontrolling interest |
524 | 29 | 406 | |||||||||||
|
|
|
|
|
|
|||||||||
Comprehensive income (loss) attributable to Regency Energy Partners LP |
$ | 22,146 | $ | (4,924 | ) | $ | 15,279 | |||||||
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial statements
5
Condensed Consolidated Statements of Cash Flows
(in thousands)
(unaudited)
Successor | Predecessor | |||||||||||||
Six Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from January 1, 2010 to May 25, 2010 |
||||||||||||
OPERATING ACTIVITIES: |
||||||||||||||
Net income (loss) |
$ | 29,142 | $ | (4,895 | ) | $ | (4,946 | ) | ||||||
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities: |
||||||||||||||
Depreciation and amortization, including debt issuance cost amortization and bond premium amortization |
83,587 | 11,330 | 49,363 | |||||||||||
Write-off of debt issuance costs |
| | 1,780 | |||||||||||
Amortization of excess fair value of unconsolidated affiliates |
2,923 | 365 | | |||||||||||
Equity in earnings of unconsolidated affiliates |
(58,898 | ) | (8,486 | ) | (15,872 | ) | ||||||||
Derivative valuation changes |
(5,826 | ) | 6,921 | 12,004 | ||||||||||
Loss on asset sales, net |
181 | 10 | 303 | |||||||||||
Unit-based compensation expenses |
1,747 | 137 | 12,070 | |||||||||||
Cash flow changes in current assets and liabilities: |
||||||||||||||
Trade accounts receivable, accrued revenues and related party receivables |
(8,847 | ) | 13,843 | (11,272 | ) | |||||||||
Other current assets |
964 | 585 | 2,516 | |||||||||||
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues |
28,577 | (15,460 | ) | 8,649 | ||||||||||
Other current liabilities |
(2,764 | ) | (20,497 | ) | 22,614 | |||||||||
Distributions received from unconsolidated affiliates |
50,510 | | 12,446 | |||||||||||
Cash flow changes in other assets and liabilities |
(182 | ) | (60 | ) | (234 | ) | ||||||||
|
|
|
|
|
|
|||||||||
Net cash flows provided by (used in) operating activities |
121,114 | (16,207 | ) | 89,421 | ||||||||||
|
|
|
|
|
|
|||||||||
INVESTING ACTIVITIES: |
||||||||||||||
Capital expenditures |
(172,236 | ) | (20,875 | ) | (63,787 | ) | ||||||||
Capital contributions to unconsolidated affiliates |
(591,681 | ) | (38,922 | ) | (20,210 | ) | ||||||||
Distribution in excess of earnings of unconsolidated affiliates |
27,990 | | | |||||||||||
Acquisitions, net of cash received |
| 12,848 | (75,114 | ) | ||||||||||
Proceeds from asset sales |
4,003 | 14 | 10,661 | |||||||||||
|
|
|
|
|
|
|||||||||
Net cash flows used in investing activities |
(731,924 | ) | (46,935 | ) | (148,450 | ) | ||||||||
|
|
|
|
|
|
|||||||||
FINANCING ACTIVITIES: |
||||||||||||||
Net borrowings under revolving credit facility |
45,000 | 37,000 | 199,008 | |||||||||||
Proceeds from issuance of senior notes |
500,000 | | | |||||||||||
Debt issuance costs |
(9,936 | ) | (132 | ) | (15,728 | ) | ||||||||
Partner contributions |
| 7,436 | | |||||||||||
Partner distributions |
(131,106 | ) | | (86,078 | ) | |||||||||
Disposition of assets between entities under common control in excess of historical cost |
25 | | (16,973 | ) | ||||||||||
Distributions to noncontrolling interest |
| | (1,135 | ) | ||||||||||
Proceeds from issuance of common units under LTIP, net of tax withholding |
506 | 150 | (4,874 | ) | ||||||||||
Proceeds from common unit issuances, net of issuance costs |
203,917 | | (89 | ) | ||||||||||
Distributions to Series A Preferred Units |
(3,891 | ) | | (1,945 | ) | |||||||||
|
|
|
|
|
|
|||||||||
Net cash flows provided by financing activities |
604,515 | 44,454 | 72,186 | |||||||||||
|
|
|
|
|
|
|||||||||
Net change in cash and cash equivalents |
(6,295 | ) | (18,688 | ) | 13,157 | |||||||||
Cash and cash equivalents at beginning of period |
9,400 | 22,984 | 9,827 | |||||||||||
|
|
|
|
|
|
|||||||||
Cash and cash equivalents at end of period |
$ | 3,105 | $ | 4,296 | $ | 22,984 | ||||||||
|
|
|
|
|
|
|||||||||
Supplemental cash flow information: |
||||||||||||||
Non-cash capital expenditures |
$ | 14,598 | $ | 16,159 | $ | 18,051 | ||||||||
Issuance of common units for an acquisition |
| 584,436 | | |||||||||||
Deemed contribution from acquisition of assets between entities under common control |
| 17,152 | | |||||||||||
Contribution receivable |
| 12,288 | |
See accompanying notes to condensed consolidated financial statements
6
Condensed Consolidated Statement of Partners Capital and Noncontrolling Interest
(dollar amounts in thousands)
(unaudited)
Regency Energy Partners LP | ||||||||||||||||||||||||
Units | ||||||||||||||||||||||||
Common | Common Unitholders |
General Partner Interest |
Accumulated Other Comprehensive Loss |
Noncontrolling Interest |
Total | |||||||||||||||||||
Balance - December 31, 2010 |
137,281,336 | $ | 2,940,732 | $ | 333,077 | $ | (11,099 | ) | $ | 31,692 | $ | 3,294,402 | ||||||||||||
Private common unit offering, net of costs |
8,500,001 | 203,917 | | | | 203,917 | ||||||||||||||||||
Issuance of common units under LTIP, net of forfeitures and tax withholding |
56,405 | 506 | | | | 506 | ||||||||||||||||||
Unit-based compensation expenses |
| 1,747 | | | | 1,747 | ||||||||||||||||||
Disposition of assets between entities under common control in excess of historical cost |
| | 25 | | | 25 | ||||||||||||||||||
Partner distributions |
| (126,404 | ) | (4,702 | ) | | | (131,106 | ) | |||||||||||||||
Accrued distributions to phantom units |
| (209 | ) | | | | (209 | ) | ||||||||||||||||
Net income |
| 25,776 | 2,842 | | 524 | 29,142 | ||||||||||||||||||
Distributions to Series A Preferred Units |
| (3,815 | ) | (76 | ) | | | (3,891 | ) | |||||||||||||||
Accretion of Series A Preferred Units |
| (97 | ) | | | | (97 | ) | ||||||||||||||||
Net cash flow hedge amounts reclassified to earnings |
| | | 8,994 | | 8,994 | ||||||||||||||||||
Change in fair value of cash flow hedges |
| | | (15,466 | ) | | (15,466 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Balance - June 30, 2011 |
145,837,742 | $ | 3,042,153 | $ | 331,166 | $ | (17,571 | ) | $ | 32,216 | $ | 3,387,964 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to condensed consolidated financial statements
7
Notes to Condensed Consolidated Financial Statements
(Tabular dollar amounts, except per unit data, are in thousands)
(unaudited)
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, processing and transporting natural gas and NGLs as well as providing contract compression and contract treating services. Regency GP LP is the Partnerships general partner and Regency GP LLC (collectively the General Partner) is the managing general partner of the Partnership and the general partner of Regency GP LP.
Basis of Presentation. In May 2010, GP Seller completed the sale of all of the outstanding membership interests of the General Partner pursuant to a Purchase Agreement (the Purchase Agreement) among itself, ETE and ETE GP (the ETE Acquisition). Prior to the closing of the Purchase Agreement, GP Seller, an affiliate of GE EFS, owned all of the outstanding limited partner interests in the General Partner and, as a result of that position, controlled the Partnership. As a result of this transaction, the outstanding voting interests of the General Partner and control of the Partnership were transferred from GE EFS to ETE.
In connection with this change in control, the Partnerships assets and liabilities were adjusted to fair value on the closing date (May 26, 2010) by application of push-down accounting (the Push-down Adjustments). Due to the Push-down Adjustments, the Partnerships unaudited condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (1) the period prior to the acquisition date (May 26, 2010), identified as Predecessor and (2) the period from May 26, 2010 forward, identified as Successor.
The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnerships Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of the Partnerships 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 inter-company 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. Certain prior year numbers have been reclassified to conform to the current year presentation.
Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the condensed consolidated financial statements. Although these estimates are based on managements available knowledge of current and expected future events, actual results could be different from those estimates.
Quarterly Distributions of Available Cash. Following are distributions declared and/or paid by the Partnership subsequent to December 31, 2010:
Quarter Ended |
Record Date |
Payment Date |
Cash Distributions (per common unit) |
|||||
December 31, 2010 |
February 7, 2011 | February 14, 2011 | $ | 0.445 | ||||
March 31, 2011 |
May 6, 2011 | May 13, 2011 | $ | 0.445 | ||||
June 30, 2011 |
August 5, 2011 | August 12, 2011 | $ | 0.45 |
8
2. Income (Loss) per Limited Partner Unit
The following tables provide a reconciliation of the numerator and denominator of the basic and diluted earnings per unit computations for the three and six months ended June 30, 2011. For the three and six months ended June 30, 2010, including successor and predecessor periods, diluted earnings per unit equaled basic earnings per unit because all instruments were antidilutive.
Three Months Ended June 30, 2011 | ||||||||||||
Income (Numerator) |
Units (Denominator) |
Per-Unit Amount |
||||||||||
Basic income from continuing operations per unit |
||||||||||||
Limited Partners interest |
$ | 10,999 | 142,937,163 | $ | 0.08 | |||||||
Effect of Dilutive Securities |
||||||||||||
Common unit options |
| 25,826 | ||||||||||
Phantom units * |
| 237,747 | ||||||||||
Series A Preferred Units |
(955 | ) | 4,614,250 | |||||||||
|
|
|
|
|||||||||
Diluted income from continuing operations per unit |
$ | 10,044 | 147,814,986 | $ | 0.07 | |||||||
|
|
|
|
|||||||||
Six Months Ended June 30, 2011 | ||||||||||||
Income (Numerator) |
Units (Denominator) |
Per-Unit Amount |
||||||||||
Basic income from continuing operations per unit |
||||||||||||
Limited Partners interest |
$ | 21,788 | 140,135,219 | $ | 0.16 | |||||||
Effect of Dilutive Securities |
||||||||||||
Common unit options |
| 28,403 | ||||||||||
Phantom units * |
| 231,251 | ||||||||||
Series A Preferred Units |
(1,537 | ) | 4,584,192 | |||||||||
|
|
|
|
|||||||||
Diluted income from continuing operations per unit |
$ | 20,251 | 144,979,065 | $ | 0.14 | |||||||
|
|
|
|
* | Amount assumes maximum conversion rate for market condition awards. |
The following data show 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 for the periods presented:
Successor | Predecessor | |||||||||||||
Three Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period
from April 1, 2010 to May 25, 2010 |
||||||||||||
Restricted (non-vested) common units |
| | 356,954 | |||||||||||
Common unit options |
| 290,150 | 290,150 | |||||||||||
Phantom units * |
| 322,750 | 351,345 | |||||||||||
Series A Preferred Units |
| 4,584,192 | 4,584,192 | |||||||||||
Successor | Predecessor | |||||||||||||
Six Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period
from January 1, 2010 to May 25, 2010 |
||||||||||||
Restricted (non-vested) common units |
| | 396,918 | |||||||||||
Common unit options |
| 290,150 | 298,400 | |||||||||||
Phantom units * |
| 322,750 | 369,346 | |||||||||||
Series A Preferred Units |
| 4,584,192 | 4,584,192 |
* | Amount assumes maximum conversion rate for market condition awards. |
9
3. Investment in Unconsolidated Affiliates
Lone Star. On May 2, 2011, Lone Star, a newly formed joint venture that is owned 70% by ETP and 30% by the Partnership, completed its acquisition of all of the membership interest in LDH, a wholly-owned subsidiary of Louis Dreyfus Highbridge Energy LLC, for $1.97 billion in cash, subject to customary post-closing purchase price adjustments. The Partnership contributed $591.7 million in cash to Lone Star, in exchange for its 30% interest. To fund a portion of this capital contribution, the Partnership issued 8,500,001 common units representing limited partnership interests with net proceeds of $203.9 million. These units were issued in a private placement conducted in accordance with the exemption from the registration requirement of the Securities Act of 1933, as amended, under section 4(2) thereof. These units were subsequently registered with the SEC. The remaining portion of the Partnerships capital contribution was funded by additional borrowings under its revolving credit facility.
Lone Star owns and operates an NGL storage, fractionation and transportation business. Lone Stars storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline transports NGLs through an intrastate pipeline system that originates in the Permian Basin in west Texas, passes through the Barnett Shale production area in north Texas and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana.
Lone Star is managed by a two-person board of directors, with the Partnership and ETP each having the right to appoint one director, and is operated by ETP. As of June 30, 2011, the carrying value of the Partnerships interest in Lone Star was $600.1 million. Amounts recorded with respect to Lone Star for the period ended June 30, 2011 are summarized in the table below:
Period from
Initial Contribution (May 2, 2011) to June 30, 2011 |
||||
Contributions to Lone Star |
$ | 591,681 | ||
Partnerships share of Lone Stars net income |
8,388 |
The summarized income statement information of Lone Star (on a 100% basis) is disclosed below:
Period from
Initial Contribution (May 2, 2011) to June 30, 2011 |
||||
Total revenues |
$ | 98,820 | ||
Operating income |
28,143 | |||
Net income |
27,958 |
Upon the completion of Lone Stars acquisition of all of the membership interests in LDH, Lone Star recorded the assets and liabilities of LDH at fair value. As a result, no basis difference currently exists between the Partnerships investment in Lone Star and the Partnerships proportionate share of the underlying equity in net assets of Lone Star, and the Partnerships equity of earnings for Lone Star reflects its proportionate share of Lone Stars net income.
HPC. The Partnership owns a 49.99% general partner interest in HPC. As of June 30, 2011 and December 31, 2010, the carrying value of the Partnerships interest in HPC was $691.2 million and $698.8 million, respectively. Amounts recorded with respect to HPC for the three and six months ended June 30, 2011 and 2010, including successor and predecessor periods, are summarized in the tables below:
Successor | Predecessor | |||||||||||||
Three Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from April 1, 2010 to May 25, 2010 |
||||||||||||
Contributions to HPC |
$ | | $ | | $ | 20,210 | ||||||||
Distributions received from HPC |
18,113 | | 8,920 | |||||||||||
Partnerships share of HPCs net income |
15,130 | 4,460 | 7,959 | |||||||||||
Amortization of excess fair value of investment in HPC |
1,461 | 365 | |
10
Successor | Predecessor | |||||||||||||
Six Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from January 1, 2010 to May 25, 2010 |
||||||||||||
Contributions to HPC |
$ | | $ | | $ | 20,210 | ||||||||
Distributions received from HPC |
34,841 | | 12,446 | |||||||||||
Partnerships share of HPCs net income |
30,205 | 4,460 | 15,872 | |||||||||||
Amortization of excess fair value of investment in HPC |
2,923 | 365 | |
The summarized income statement information of HPC (on a 100% basis) is disclosed below:
Three Months Ended June 30, | ||||||||
2011 | 2010 | |||||||
Total revenues |
$ | 48,585 | $ | 44,375 | ||||
Operating income |
30,515 | 25,950 | ||||||
Net income |
30,265 | 25,871 | ||||||
Six Months Ended June 30, | ||||||||
2011 | 2010 | |||||||
Total revenues |
$ | 97,234 | $ | 79,564 | ||||
Operating income |
60,842 | 44,416 | ||||||
Net income |
60,421 | 44,274 |
MEP. The Partnership owns a 49.9% interest in MEP. As of June 30, 2011 and December 31, 2010, the carrying value of the Partnerships interest in MEP was $629.1 million and $652.5 million, respectively. Amounts recorded with respect to MEP for the three and six months ended June 30, 2011 and 2010 are summarized in the tables below:
Three Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
|||||||
Distributions received from MEP |
$ | 18,222 | $ | | ||||
Partnerships share of MEPs net income |
10,110 | 4,026 | ||||||
Six Months Ended June 30, 2011 |
Period from Acquisition (May 26, 2010) to June 30, 2010 |
|||||||
Distributions received from MEP |
$ | 43,659 | $ | | ||||
Partnerships share of MEPs net income |
20,305 | 4,026 |
The summarized income statement information of MEP (on a 100% basis) is disclosed below:
Three Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
|||||||
Total revenues |
$ | 64,943 | $ | 21,269 | ||||
Operating income |
33,190 | 11,499 | ||||||
Net income |
20,276 | 8,068 | ||||||
Six Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
|||||||
Total revenues |
$ | 129,767 | $ | 21,269 | ||||
Operating income |
66,455 | 11,499 | ||||||
Net income |
40,686 | 8,068 |
11
4. Derivative Instruments
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 General Partner is responsible for delegation of transaction authority levels, and the Audit and Risk Management Committee of the General Partner is responsible for the oversight of these risks, including monitoring exposure limits. The Audit and Risk Management Committee receives regular briefings on exposures and overall risk management in the context of market activities.
Commodity Price Risk. The Partnership is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as other market forces. Both the Partnerships profitability and cash flow are affected by the inherent volatility of these commodities which could adversely affect its ability to make distributions to its 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 its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, the Partnership may not be able to match pricing terms or cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions with derivative contracts are prohibited under the Partnerships policies.
At June 30, 2011, all of the Partnerships commodity swaps were accounted for as cash flow hedges.
Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. As of June 30, 2011, the Partnership had $330 million of outstanding borrowings exposed to variable interest rate risk. In April 2010, the Partnership entered into two-year interest rate swaps related to $250 million of borrowings under its revolving credit facility, effectively locking the base rate, exclusive of applicable margins, for these borrowings at 1.325% through April 2012. The Partnership accounts for these interest rate swaps using the mark-to-market method of accounting.
Credit Risk. The Partnerships resale of NGLs, condensate and 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 parental guarantee from a parent company with potentially better credit.
The Partnership is exposed to credit risk from its derivative counterparties. The Partnership does not require collateral from these counterparties. The Partnership deals primarily with financial institutions when entering into financial derivatives, and utilizes master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnerships counterparties fail to perform under existing swap contracts, the Partnerships maximum loss as of June 30, 2011 would be $1.4 million which would be reduced in full due to the netting feature. The Partnership has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets.
Embedded Derivatives. The Series A Preferred Units contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders conversion option and the Partnerships call option. These embedded derivatives are accounted for using mark-to-market accounting. The Partnership does not expect the embedded derivatives to affect its cash flows.
Quantitative Disclosures. The Partnership expects to reclassify $16.4 million of net hedging losses to revenues from accumulated other comprehensive loss in the next 12 months.
12
The Partnerships derivative assets and liabilities, including credit risk adjustments, as of June 30, 2011 and December 31, 2010 are detailed below:
Assets | Liabilities | |||||||||||||||
June 30, 2011 | December 31, 2010 | June 30, 2011 | December 31, 2010 | |||||||||||||
Derivatives designated as cash flow hedges |
||||||||||||||||
Current amounts |
||||||||||||||||
Commodity contracts |
$ | 1,075 | $ | 2,650 | $ | 18,827 | $ | 11,421 | ||||||||
Long-term amounts |
||||||||||||||||
Commodity contracts |
366 | 23 | 1,535 | 3,271 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total cash flow hedging instruments |
1,441 | 2,673 | 20,362 | 14,692 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Derivatives not designated as cash flow hedges |
||||||||||||||||
Current amounts |
||||||||||||||||
Interest rate contracts |
| | 1,852 | 1,751 | ||||||||||||
Long-term amounts |
||||||||||||||||
Interest rate contracts |
| | | 833 | ||||||||||||
Embedded derivatives in Series A Preferred Units |
| | 51,498 | 57,023 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total derivatives not designated as cash flow hedges |
| | 53,350 | 59,607 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total derivatives |
$ | 1,441 | $ | 2,673 | $ | 73,712 | $ | 74,299 | ||||||||
|
|
|
|
|
|
|
|
The Partnerships statement of operations for the three months ended June 30, 2011 and 2010 were impacted by derivative instruments activities as follows:
Successor | Predecessor | |||||||||||||||
Three Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from April 1, 2010 to May 25, 2010 |
||||||||||||||
Location of Gain/(Loss) Recognized in Income |
Change in Value Recognized in |
|||||||||||||||
Derivatives in cash flow hedging relationships: |
||||||||||||||||
Commodity derivatives |
Revenues | $ | 1,530 | $ | | $ | 7,428 | |||||||||
Location of Gain/(Loss) Recognized in Income |
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) |
|||||||||||||||
Derivatives in cash flow hedging relationships: |
||||||||||||||||
Commodity derivatives |
Revenues | $ | (7,133 | ) | $ | | $ | (709 | ) | |||||||
Location of Gain/(Loss) Recognized in Income |
Amount of Gain/(Loss) Recognized in Income on Ineffective Portion |
|||||||||||||||
Derivatives in cash flow hedging relationships: |
||||||||||||||||
Commodity derivatives |
Revenues | $ | (362 | ) | $ | | $ | (301 | ) | |||||||
Location of Gain/(Loss) Recognized in Income |
Amount of Gain/(Loss) from Designation Amortized from AOCI into Income |
|||||||||||||||
Derivatives not designated in a hedging relationship: |
||||||||||||||||
Commodity derivatives |
Revenues | $ | | $ | | $ | 1,221 | |||||||||
Location of Gain/(Loss) Recognized in Income |
Amount of Gain/(Loss) Recognized in Income on Derivatives |
|||||||||||||||
Derivatives not designated in a hedging relationship: |
||||||||||||||||
Commodity derivatives (credit risk adjustment) |
Revenues | $ | (47 | ) | $ | (824 | ) | $ | 12 | |||||||
Interest rate swap derivatives |
Interest expense, net | (228 | ) | (1,715 | ) | (824 | ) | |||||||||
Embedded derivatives |
Other income & deductions | 2,950 | (3,606 | ) | (654 | ) | ||||||||||
|
|
|
|
|
|
|||||||||||
$ | 2,675 | $ | (6,145 | ) | $ | (1,466 | ) | |||||||||
|
|
|
|
|
|
13
The Partnerships statement of operations for the six months ended June 30, 2011 and 2010 were impacted by derivative instruments activities as follows:
Successor | Predecessor | |||||||||||||||
Six Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from January 1, 2010 to May 25, 2010 |
||||||||||||||
Location of Gain/(Loss) Recognized in Income |
Change in Value Recognized in |
|||||||||||||||
Derivatives in cash flow hedging relationships: |
||||||||||||||||
Commodity derivatives |
Revenues | $ | (15,466 | ) | $ | | $ | 14,371 | ||||||||
Location of Gain/(Loss) Recognized in Income |
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) |
|||||||||||||||
Derivatives in cash flow hedging relationships: |
||||||||||||||||
Commodity derivatives |
Revenues | $ | (8,994 | ) | $ | | $ | (5,200 | ) | |||||||
Interest rate swap derivatives |
Interest expense | | | (1,060 | ) | |||||||||||
|
|
|
|
|
|
|||||||||||
$ | (8,994 | ) | $ | | $ | (6,260 | ) | |||||||||
|
|
|
|
|
|
|||||||||||
Location of Gain/(Loss) Recognized in Income |
Amount of Gain/(Loss) Recognized in Income on Ineffective Portion |
|||||||||||||||
Derivatives in cash flow hedging relationships: |
||||||||||||||||
Commodity derivatives |
Revenues | $ | (274 | ) | $ | | $ | (799 | ) | |||||||
Location of Gain/(Loss) Recognized in Income |
Amount of Gain/(Loss) from Designation Amortized from AOCI into Income |
|||||||||||||||
Derivatives not designated in a hedging relationship: |
||||||||||||||||
Commodity derivatives |
Revenues | $ | | $ | | $ | 4,115 | |||||||||
Location of Gain/(Loss) Recognized in Income |
Amount of Gain/(Loss) Recognized in Income on Derivatives |
|||||||||||||||
Derivatives not designated in a hedging relationship: |
||||||||||||||||
Commodity derivatives (credit risk adjustment) |
Revenues | $ | 12 | $ | (824 | ) | $ | 1,247 | ||||||||
Interest rate swap derivatives |
Interest expense, net | (487 | ) | (1,715 | ) | (824 | ) | |||||||||
Embedded derivatives |
Other income & deductions | 5,525 | (3,606 | ) | (4,039 | ) | ||||||||||
|
|
|
|
|
|
|||||||||||
$ | 5,050 | $ | (6,145 | ) | $ | (3,616 | ) | |||||||||
|
|
|
|
|
|
5. Long-term Debt
Obligations in the form of senior notes and borrowings under the revolving credit facility are as follows:
June 30, 2011 | December 31, 2010 | |||||||
Senior notes |
$ | 1,355,613 | $ | 856,061 | ||||
Revolving loans |
330,000 | 285,000 | ||||||
|
|
|
|
|||||
Total |
1,685,613 | 1,141,061 | ||||||
Less: current portion |
| | ||||||
|
|
|
|
|||||
Long-term debt |
$ | 1,685,613 | $ | 1,141,061 | ||||
|
|
|
|
|||||
Availability under revolving credit facility: |
||||||||
Total credit facility limit |
$ | 900,000 | $ | 900,000 | ||||
Revolving loans |
(330,000 | ) | (285,000 | ) | ||||
Letters of credit |
(11,015 | ) | (16,015 | ) | ||||
|
|
|
|
|||||
Total available |
$ | 558,985 | $ | 598,985 | ||||
|
|
|
|
14
Scheduled maturities of long-term debt at June 30, 2011 are as follows:
Years Ending December 31, |
Amount | |||
2011 (remainder) |
$ | | ||
2012 |
| |||
2013 |
| |||
2014 |
330,000 | |||
2015 |
| |||
Thereafter |
1,350,000 | * | ||
|
|
|||
Total |
$ | 1,680,000 | ||
|
|
* | Excludes an unamortized premium of $5.6 million as of June 30, 2011. |
Revolving Credit Facility. The Partnerships $900 million revolving credit facility expires on June 15, 2014. The revolving credit facility and guarantees are senior to the Partnerships and each guarantors unsecured obligations, to the extent of the value of the assets securing such obligations. The revolving credit facility contains financial covenants requiring RGS and its subsidiaries to maintain debt to consolidated EBITDA, as defined in the credit agreement, ratio less than 5.25. At June 30, 2011, RGS and its subsidiaries were in compliance with these covenants.
The outstanding balance under the revolving 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 average interest rates, including commitment fees, were 3.25% and 3.92%, respectively, during the six months ended June 30, 2011 and 2010.
On May 2, 2011, the Partnership amended its Fifth Amended and Restated Credit Agreement to permit the acquisition of equity interests in Lone Star and to allow for additional investments in Lone Star of up to $150 million.
Senior Notes. In May 2011, the Partnership and Finance Corp. issued $500 million in senior notes that mature on July 15, 2021 (2021 Notes). The senior notes bear interest at 6.5% payable semi-annually in arrears on January 15 and July 15, commencing January 15, 2012. The Partnership capitalized $9.8 million in debt issuance costs that will be amortized to interest expense, net over the term of the senior notes. The proceeds were used to repay borrowings outstanding under the Partnerships revolving credit facility.
At any time prior to July 15, 2014, the Partnership may redeem up to 35% of the senior notes at a price equal to 106.5% plus accrued interest. Beginning on July 15 of the years indicated below, the Partnership may redeem all or part of the 2021 Notes at the redemption prices, expressed as percentages of the principal amount, set forth below:
July 15 of year ending: |
Percentage of Redemption | |||
2016 |
103.250 | % | ||
2017 |
102.167 | % | ||
2018 |
101.083 | % | ||
2019 and thereafter at 100% |
100.000 | % |
Upon a change of control, as defined in the indenture, followed by a rating decline within 90 days, each holder of the 2021 Notes will be entitled to require the Partnership to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any. The Partnerships ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including the Partnerships revolving credit facility.
The 2021 Notes contain various covenants that limit, among other things, the Partnerships 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. |
If the 2021 Notes achieve investment grade ratings by both Moodys and S&P and no default or event of default has occurred and is continuing, the Partnership will no longer be subject to many of the foregoing covenants. At June 30, 2011, the Partnership was in compliance with these covenants.
15
Finance Corp., co-issuer for all of the Partnerships senior notes, has no operations and will not have revenues other than as may be incidental. Since the Partnership has no independent operations, the guarantees are fully unconditional and joint and several of its existing unconsolidated subsidiaries, except for one minor subsidiary, and the Partnership has not included condensed consolidated financial information of guarantors of the senior notes.
6. Commitments and Contingencies
Legal. The Partnership is involved in various claims, lawsuits and audits by taxing authorities incidental to its business. These claims and lawsuits in the aggregate are not expected to have a material adverse effect on the Partnerships business, financial condition, results of operations or cash flows.
Keyes Litigation. In August 2008, Keyes Helium Company, LLC (Keyes) filed suit against RGS, the Partnership, the General Partner and various other subsidiaries. Keyes entered into an output contract with the Partnerships predecessor-in-interest in 1996 under which it purchased all of the helium produced at the Lakin, Kansas processing plant. 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, the Partnership no longer delivered any helium to Keyes. In its suit, Keyes alleges it is entitled to damages for the costs of covering its purchases of helium. On May 7, 2010, the jury rendered a verdict in favor of the Partnership. No damages were awarded to the Plaintiffs. Plaintiffs have appealed the verdict. The hearing on appeal will likely take place in late 2011 or early 2012.
7. Series A Preferred Units
On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units. As of June 30, 2011, the Series A Preferred Units were convertible to 4,620,152 common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80 million plus all accrued but unpaid distributions thereon. The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit beginning with the quarter ending March 31, 2010, if outstanding on the record dates of the Partnerships common unit distributions. Effective as of March 2, 2010, holders can elect to convert Series A Preferred Units to common units at any time in accordance with the partnership agreement.
The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for the six months ended June 30, 2011:
Units | Amount | |||||||
Balance at January 1, 2011 |
4,371,586 | $ | 70,943 | |||||
Accretion to redemption value |
| 97 | ||||||
|
|
|
|
|||||
Ending balance as of June 30, 2011 |
4,371,586 | $ | 71,040 | * | ||||
|
|
|
|
* | This amount will be accreted to $80 million plus any accrued and unpaid distributions by deducting amounts from partners capital over the remaining period until the mandatory redemption date of September 2, 2029. |
8. Related Party Transactions
As of June 30, 2011 and December 31, 2010, details of the Partnerships related party receivables and related party payables were as follows:
June 30, 2011 | December 31, 2010 | |||||||
Related party receivables |
||||||||
EPD and its subsidiaries |
$ | 18,649 | $ | 25,539 | ||||
HPC |
7,846 | 5,823 | ||||||
ETE and its subsidiaries |
6,669 | 970 | ||||||
Other |
1,423 | 10 | ||||||
|
|
|
|
|||||
Total related party receivables |
$ | 34,587 | $ | 32,342 | ||||
|
|
|
|
|||||
Related party payables |
||||||||
EPD and its subsidiaries |
$ | 754 | $ | 1,323 | ||||
HPC |
1,966 | 760 | ||||||
ETE and its subsidiaries |
34,443 | 1,245 | ||||||
Other |
22 | 10 | ||||||
|
|
|
|
|||||
Total related party payables |
$ | 37,185 | $ | 3,338 | ||||
|
|
|
|
Transactions with ETE and its subsidiaries. Under a May 26, 2010 service agreement with Services Co., Services Co. performs certain services for the Partnership. The Partnership pays Services Co.s direct expenses for these services, plus an annual fee of $10 million, and receives the benefit of any cost savings recognized for these services. The services agreement has a five year term from May 26, 2010 to May 26, 2015, subject to earlier termination rights in the event of a change in control, the failure to achieve certain cost savings for the Partnership or upon an event of default. Also, the Partnership, together with Regency GP LP and RGS entered into an operation and service agreement (the Operations Agreement) with ETC. Under the Operations Agreement, ETC will perform certain operations, maintenance and related services reasonably required to operate and maintain certain facilities owned by the Partnership. Pursuant to the Operations Agreement, the Partnership will reimburse ETC for actual costs and expenses incurred in connection with the provision of these services based on an annual budget agreed-upon by both parties. The Operations Agreement has an initial term of one year and automatically renews on a year-to-year basis upon expiration of the initial term.
The total fees related to these service contracts were $4.2 million and $8.1 million for the three and six months ended June 30, 2011, and for the period from the acquisition, May 26, 2010, to June 30, 2010 was $0.8 million.
In conjunction with distributions by the Partnership to the limited and general partner interests, ETE received cash distributions of $14.1 million and $28.1 million during the three and six months ended June 30, 2011.
The Partnerships Contract Compression segment provides contract compression services to subsidiaries of ETP and records revenue in gathering, transportation and other fees on the statement of operations.
16
The Partnerships Contract Compression segment sold compression equipment to a subsidiary of ETP for $5.5 million and $6.3 million for the three and six months ended June 30, 2011, respectively. As these transactions are between entities under common control, partners capital was increased by $25 thousand, which represented a deemed contribution of the excess sales price over the carrying amounts.
Prior to December 31, 2010, the employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services were employees of the General Partner. Pursuant to the Partnership agreement, the General Partner receives a monthly reimbursement for all direct and indirect expenses incurred on behalf of the Partnership. Effective January 1, 2011, certain employees of the Partnership became employees of ETP, and the Partnership reimburses ETP for all direct and indirect expenses incurred on behalf of the Partnership related to those employees. For the six months ended June 30, 2011, reimbursements of $24.6 million and $8.6 million were recorded to the General Partner and to ETP, respectively, in the Partnerships financial statements as operating expenses or general and administrative expenses, as appropriate. For the six months ended June 30, 2010, reimbursements of $5.7 million, $10.4 million and $31.1 million to the General Partner were recorded, respectively, during the periods from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010 and from January 1, 2010 to May 25, 2010 in the Partnerships financial statements as operating expenses or general and administrative expenses.
Transactions with HPC. Under a master services agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. During the three and six months ended June 30, 2011, from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010 and from January 1, 2010 to May 25, 2010, the related party general and administrative expenses reimbursed to the Partnership were $4.2 million, $8.4 million, $1.4 million, $2.8 million and $6.9 million, respectively, which is recorded in gathering, transportation and other fees on the statement of operations.
The Partnerships Contract Compression segment provides contract compression services to HPC and records revenues in gathering, transportation and other fees in the statement of operations. The Partnership also receives transportation services from HPC and records it as cost of sales.
Transactions with Enterprise. Enterprise Products Partners L.P. (EPD) owns a portion of ETEs outstanding common units; therefore, it is considered a related party along with any of its subsidiaries. The Partnership, in the ordinary course of business, sells natural gas and NGLs to subsidiaries of EPD and records the revenues in gas sales and NGL sales. The Partnership also incurs NGL processing fees and transportation fees with subsidiaries of EPD and records these fees as cost of sales.
9. Segment Information
During the six months ended June 30, 2011, the Partnership changed the name of the Transportation segment to Joint Ventures, which represents the Partnerships equity method investments in its three unconsolidated joint ventures: HPC, MEP and Lone Star. In addition, the disposition of the east Texas assets in July 2010 impacts the Gathering and Processing segment, as the results of those operations are now presented within discontinued operations and excluded from the segment information table. Accordingly, the Partnership has recast the segment information for the corresponding periods in 2010.
Gathering and Processing. The Partnership provides wellhead-to-market services to producers of natural gas, which include gathering raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems.
Joint Ventures. The Partnership owns a 49.99% general partner interest in HPC, which delivers natural gas from northwest Louisiana to downstream pipelines and markets through the 450-mile Regency Intrastate Gas pipeline system. The
17
Partnership owns a 49.9% interest in MEP, which owns approximately 500 miles of natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi into Alabama. The Partnership has a 30% interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, storage and processing facilities located in the states of Texas, Mississippi and Louisiana.
Contract Compression. The Partnership owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems.
Contract Treating. The Partnership owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management, to natural gas producers and midstream pipeline companies.
Corporate and Others. The Corporate and Others segment comprises a 10 mile interstate pipeline and the Partnerships corporate offices.
The Partnership accounts for intersegment revenues as if the revenues were to third parties, exclusive of certain cost of capital charges.
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 the Corporate and Others segments is defined as total revenues, including service fees, less cost of sales. In the Contract Compression segment and Contract Treating segment, segment margin is defined as revenues less direct costs.
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. We do not record segment margin for the Joint Ventures segment because we record our ownership percentages of the net income in HPC, MEP and Lone Star as income from unconsolidated affiliates in accordance with the equity method of accounting.
18
Results for each period, together with amounts related to balance sheets for each segment, are shown below:
Successor | Predecessor | |||||||||||||
Three Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from April 1, 2010 to May 25, 2010 |
||||||||||||
External Revenues |
||||||||||||||
Gathering and Processing |
$ | 303,203 | $ | 83,778 | $ | 173,206 | ||||||||
Joint Ventures |
| | | |||||||||||
Contract Compression |
38,072 | 12,054 | 23,992 | |||||||||||
Contract Treating |
10,842 | | | |||||||||||
Corporate and Others |
4,381 | 1,148 | 3,067 | |||||||||||
Eliminations |
| | | |||||||||||
|
|
|
|
|
|
|||||||||
Total |
$ | 356,498 | $ | 96,980 | $ | 200,265 | ||||||||
|
|
|
|
|
|
|||||||||
Intersegment Revenues |
||||||||||||||
Gathering and Processing |
$ | | $ | | $ | | ||||||||
Joint Ventures |
| | | |||||||||||
Contract Compression |
2,917 | 1,998 | 3,794 | |||||||||||
Contract Treating |
| | | |||||||||||
Corporate and Others |
110 | 22 | 52 | |||||||||||
Eliminations |
(3,027 | ) | (2,020 | ) | (3,846 | ) | ||||||||
|
|
|
|
|
|
|||||||||
Total |
$ | | $ | | $ | | ||||||||
|
|
|
|
|
|
|||||||||
Segment Margin |
||||||||||||||
Gathering and Processing |
$ | 50,495 | $ | 14,373 | $ | 35,195 | ||||||||
Joint Ventures |
| | | |||||||||||
Contract Compression |
36,973 | 12,488 | 25,326 | |||||||||||
Contract Treating |
7,701 | | | |||||||||||
Corporate and Others |
4,762 | 1,943 | 3,031 | |||||||||||
Eliminations |
(2,908 | ) | (1,998 | ) | (3,794 | ) | ||||||||
|
|
|
|
|
|
|||||||||
Total |
$ | 97,023 | $ | 26,806 | $ | 59,758 | ||||||||
|
|
|
|
|
|
|||||||||
Operation and Maintenance |
||||||||||||||
Gathering and Processing |
$ | 19,528 | $ | 7,463 | $ | 13,390 | ||||||||
Joint Ventures |
| | | |||||||||||
Contract Compression |
16,310 | 4,924 | 9,698 | |||||||||||
Contract Treating |
675 | | | |||||||||||
Corporate and Others |
397 | 13 | 21 | |||||||||||
Eliminations |
(2,914 | ) | (1,998 | ) | (3,794 | ) | ||||||||
|
|
|
|
|
|
|||||||||
Total |
$ | 33,996 | $ | 10,402 | $ | 19,315 | ||||||||
|
|
|
|
|
|
19
Successor | Predecessor | |||||||||||||
Six Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from January 1, 2010 to May 25, 2010 |
||||||||||||
External Revenues |
||||||||||||||
Gathering and Processing |
$ | 569,175 | $ | 83,778 | $ | 438,804 | ||||||||
Joint Ventures |
| | | |||||||||||
Contract Compression |
76,508 | 12,054 | 58,971 | |||||||||||
Contract Treating |
19,275 | | | |||||||||||
Corporate and Others |
8,792 | 1,148 | 7,275 | |||||||||||
Eliminations |
| | | |||||||||||
|
|
|
|
|
|
|||||||||
Total |
$ | 673,750 | $ | 96,980 | $ | 505,050 | ||||||||
|
|
|
|
|
|
|||||||||
Intersegment Revenues |
||||||||||||||
Gathering and Processing |
$ | | $ | | $ | | ||||||||
Joint Ventures |
| | | |||||||||||
Contract Compression |
9,470 | 1,998 | 9,126 | |||||||||||
Contract Treating |
| | | |||||||||||
Corporate and Others |
177 | 22 | 91 | |||||||||||
Eliminations |
(9,647 | ) | (2,020 | ) | (9,217 | ) | ||||||||
|
|
|
|
|
|
|||||||||
Total |
$ | | $ | | $ | | ||||||||
|
|
|
|
|
|
|||||||||
Segment Margin |
||||||||||||||
Gathering and Processing |
$ | 104,295 | $ | 14,373 | $ | 85,997 | ||||||||
Joint Ventures |
| | | |||||||||||
Contract Compression |
78,413 | 12,488 | 62,356 | |||||||||||
Contract Treating |
14,952 | | | |||||||||||
Corporate and Others |
9,815 | 1,943 | 8,045 | |||||||||||
Eliminations |
(9,461 | ) | (1,998 | ) | (9,126 | ) | ||||||||
|
|
|
|
|
|
|||||||||
Total |
$ | 198,014 | $ | 26,806 | $ | 147,272 | ||||||||
|
|
|
|
|
|
|||||||||
Operation and Maintenance |
||||||||||||||
Gathering and Processing |
$ | 42,470 | $ | 7,463 | $ | 33,430 | ||||||||
Joint Ventures |
| | | |||||||||||
Contract Compression |
32,702 | 4,924 | 23,476 | |||||||||||
Contract Treating |
1,409 | | | |||||||||||
Corporate and Others |
442 | 13 | 59 | |||||||||||
Eliminations |
(9,467 | ) | (1,998 | ) | (9,123 | ) | ||||||||
|
|
|
|
|
|
|||||||||
Total |
$ | 67,556 | $ | 10,402 | $ | 47,842 | ||||||||
|
|
|
|
|
|
The tables below provide a reconciliation of total segment margin to income from continuing operations before income taxes:
Successor | Predecessor | |||||||||||||
Three Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from April 1, 2010 to May 25, 2010 |
||||||||||||
Total segment margin |
$ | 97,023 | $ | 26,806 | $ | 59,758 | ||||||||
Operation and maintenance |
(33,996 | ) | (10,402 | ) | (19,315 | ) | ||||||||
General and administrative |
(17,551 | ) | (7,104 | ) | (21,809 | ) | ||||||||
Loss on assets sales, net |
(153 | ) | (10 | ) | (19 | ) | ||||||||
Depreciation and amortization |
(40,503 | ) | (10,545 | ) | (16,889 | ) | ||||||||
Income from unconsolidated affiliates |
32,167 | 8,121 | 7,959 | |||||||||||
Interest expense, net |
(24,689 | ) | (8,081 | ) | (14,059 | ) | ||||||||
Other income and deductions, net |
2,641 | (3,521 | ) | (624 | ) | |||||||||
|
|
|
|
|
|
|||||||||
Income (loss) from continuing operations before income taxes |
$ | 14,939 | $ | (4,736 | ) | $ | (4,998 | ) | ||||||
|
|
|
|
|
|
20
Successor | Predecessor | |||||||||||||
Six Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from January 1, 2010 to May 25, 2010 |
||||||||||||
Total segment margin |
$ | 198,014 | $ | 26,806 | $ | 147,272 | ||||||||
Operation and maintenance |
(67,556 | ) | (10,402 | ) | (47,842 | ) | ||||||||
General and administrative |
(36,660 | ) | (7,104 | ) | (37,212 | ) | ||||||||
Loss on assets sales, net |
(181 | ) | (10 | ) | (303 | ) | ||||||||
Depreciation and amortization |
(80,739 | ) | (10,545 | ) | (41,784 | ) | ||||||||
Income from unconsolidated affiliates |
55,975 | 8,121 | 15,872 | |||||||||||
Interest expense, net |
(44,696 | ) | (8,081 | ) | (34,541 | ) | ||||||||
Loss on debt refinancing, net |
| | (1,780 | ) | ||||||||||
Other income and deductions, net |
5,055 | (3,521 | ) | (3,897 | ) | |||||||||
|
|
|
|
|
|
|||||||||
Income (loss) from continuing operations before income taxes |
$ | 29,212 | $ | (4,736 | ) | $ | (4,215 | ) | ||||||
|
|
|
|
|
|
The table below provides a listing of assets reflected in the consolidated balance sheet for each segment:
June 30, 2011 | December 31, 2010 | |||||||
Gathering and Processing |
$ | 1,800,025 | $ | 1,724,682 | ||||
Joint Ventures |
1,920,412 | 1,351,256 | ||||||
Contract Compression |
1,409,239 | 1,411,325 | ||||||
Contract Treating |
221,110 | 220,584 | ||||||
Corporate and Others |
77,343 | 62,357 | ||||||
|
|
|
|
|||||
Total |
$ | 5,428,129 | $ | 4,770,204 | ||||
|
|
|
|
10. Equity-Based Compensation
The Partnerships LTIP for its employees, directors and consultants authorizes grants up to 3,565,584 common units. LTIP compensation expense of $0.8 million, $1.7 million, $0.1 million, $10.4 million and $12.1 million is recorded in general and administrative expense in the statement of operations for the three and six months ended June 30, 2011 and for the periods from May 26, 2010 to June 30, 2010, April 1, 2010 to May 25, 2010 and from January 1, 2010 to May 25, 2010, respectively.
Common Unit Options. The common unit options activity during the six months ended June 30, 2011 is as follows:
2011 |
||||||||||||||||
Common Unit Options |
Units | Weighted Average Exercise Price |
Weighted Average Contractual Term (Years) |
Aggregate Intrinsic Value * |
||||||||||||
Outstanding at the beginning of period (January 1, 2011) |
201,950 | $ | 21.93 | |||||||||||||
Granted |
| | ||||||||||||||
Exercised |
(32,100 | ) | 20.21 | $ | 204 | |||||||||||
Forfeited or expired |
(3,800 | ) | 26.39 | |||||||||||||
|
|
|||||||||||||||
Outstanding at end of period |
166,050 | 22.13 | 4.9 | 652 | ||||||||||||
|
|
|||||||||||||||
Exercisable at the end of the period (June 30, 2011) |
166,050 | 652 |
* | Intrinsic value equals the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented. Unit options with an exercise price greater than the end of the period closing market price are excluded. |
During the six months ended June 30, 2011, the Partnership received $0.7 million in proceeds from the exercise of unit options.
Phantom Units. All phantom units granted prior to November 2010 were in substance two grants composed of (1) service condition grants with graded vesting over three years; and (2) market condition grants with cliff vesting based upon the Partnerships relative ranking in total unitholder return among 20 peer companies. Distributions related to these unvested phantom units will be accrued and paid upon vesting. All phantom units granted after November 2010 were service condition grants only with graded vesting over five years. Distributions related to these unvested phantom units will be paid concurrent with the Partnerships distribution for common units.
21
The following table presents phantom units activity for the six months ended June 30, 2011:
2011 |
||||||||
Phantom Units |
Units | Weighted Average Grant Date Fair Value |
||||||
Outstanding at the beginning of the period (January 1, 2011) |
742,517 | $ | 23.61 | |||||
Service condition grants |
68,745 | 26.21 | ||||||
Market condition grants |
| | ||||||
Vested service condition |
(20,980 | ) | 20.69 | |||||
Vested market condition |
(8,550 | ) | 19.52 | |||||
Forfeited service condition |
(56,900 | ) | 25.07 | |||||
Forfeited market condition |
(6,660 | ) | 19.52 | |||||
|
|
|||||||
Total outstanding at end of period (June 30, 2011) |
718,172 | 24.77 | ||||||
|
|
The Partnership expects to recognize $13 million of compensation expense related to non-vested phantom units over a period of 4.2 years.
11. Fair Value Measures
The fair value measurement provisions establish a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:
| Level 1unadjusted quoted prices for identical assets or liabilities in active accessible markets; |
| Level 2inputs that are observable in the marketplace other than those classified as Level 1; and |
| Level 3inputs that are unobservable in the marketplace and significant to the valuation. |
Entities are encouraged to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation.
The Partnerships financial assets and liabilities measured at fair value on a recurring basis are derivatives related to interest rate and commodity swaps and embedded derivatives in the Series A Preferred Units. Derivatives related to interest rate and commodity swaps are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as future interest rates and commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instruments term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. Derivatives related to Series A Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected volatility, and are classified as Level 3 in the hierarchy.
The following table presents the Partnerships derivative assets and liabilities measured at fair value on a recurring basis:
Fair Value Measurements at June 30, 2011 | Fair Value Measurements at December 31, 2010 | |||||||||||||||||||||||
Fair Value Total | Significant Observable Inputs (Level 2) |
Unobservable Inputs (Level 3) |
Fair Value Total | Significant Observable Inputs (Level 2) |
Unobservable Inputs (Level 3) |
|||||||||||||||||||
Assets: |
||||||||||||||||||||||||
Commodity Derivatives: |
||||||||||||||||||||||||
Natural Gas |
$ | 1,374 | $ | 1,374 | $ | | $ | 2,481 | $ | 2,481 | $ | | ||||||||||||
NGLs |
67 | 67 | | 192 | 192 | | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total Assets |
$ | 1,441 | $ | 1,441 | $ | | $ | 2,673 | $ | 2,673 | $ | | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Liabilities: |
||||||||||||||||||||||||
Interest Rate Derivatives |
$ | 1,852 | $ | 1,852 | $ | | $ | 2,584 | $ | 2,584 | $ | | ||||||||||||
Commodity Derivatives: |
||||||||||||||||||||||||
Natural Gas |
| | | 427 | 427 | | ||||||||||||||||||
NGLs |
16,711 | 16,711 | | 10,684 | 10,684 | | ||||||||||||||||||
Condensate |
3,651 | 3,651 | | 3,581 | 3,581 | | ||||||||||||||||||
Embedded Derivatives in Series A Preferred Units |
51,498 | | 51,498 | 57,023 | | 57,023 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total Liabilities |
$ | 73,712 | $ | 22,214 | $ | 51,498 | $ | 74,299 | $ | 17,276 | $ | 57,023 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
22
The following table presents the changes in Level 3 derivatives measured on a recurring basis for the six months ended June 30, 2011. There were no transfers between the fair value hierarchy levels for the six months ended June 30, 2011.
Balance at January 1, 2011 |
$ | 57,023 | ||
Net unrealized gain included in other income and deductions, net |
(5,525 | ) | ||
|
|
|||
Balance at June 30, 2011 |
$ | 51,498 | ||
|
|
The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. Long-term debt, other than the senior notes, is comprised of borrowings under which interest accrues under a floating interest rate structure. Accordingly, the carrying value approximates fair value.
The estimated fair value of the 2016 Notes, based on third party market value quotations as of June 30, 2011 and December 31, 2010 was $279.4 million and $274.4 million, respectively. The estimated fair value of the 2018 Notes, based on third party market value quotations as of June 30, 2011 and December 31, 2010 was $624.0 million and $607.5 million, respectively. The estimated fair value of the 2021 Notes, based on third party market value quotations as of June 30, 2011 was $506.3 million.
23
Item 2. | Managements Discussion and Analysis of Financial Condition and Results of Operations |
(Tabular dollar amounts are in thousands)
The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our historical consolidated financial statements and the notes included elsewhere in this document.
OVERVIEW. We are a growth-oriented publicly-traded Delaware limited partnership formed in 2005 engaged in the gathering, treating, processing, compression and transportation of natural gas and NGLs. We focus on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville, and Marcellus shales as well as the Permian Delaware basin. Our assets are located in Louisiana, Texas, Arkansas, Pennsylvania, Mississippi, Alabama and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma.
RECENT DEVELOPMENTS
Eagle Ford Expansion. In June 2011, we entered into agreements to provide gas and condensate gathering services for a producer in the Eagle Ford Shale and to construct facilities to perform these services, including a wellhead gathering system, at an expected cost of approximately $450 million. The expansion will be owned and operated by us and will tie into our existing gathering system. In addition, we have purchased certain existing midstream assets located in the Eagle Ford Shale as part of this expansion. The expansion is scheduled for completion by 2014.
Lone Star Expansion. In May 2011, Lone Star announced a construction project of a 100,000 Bbls/d fractionator and related storage services and interconnectivity infrastructure to be constructed in Mont Belvieu, Texas, which is expected to be completed in early 2013. Our estimated capital expenditures for this project are approximately $110 million.
In June 2011, Lone Star announced it would construct an approximate 530-mile natural gas liquids pipeline that extends from Winkler County in west Texas to a processing plant in Jackson County, Texas. This pipeline will have a minimum capacity of approximately 130,000 Bbls/d with the potential to upsize the pipeline capacity depending on ongoing negotiations. Our estimated capital expenditures for this project are $210 million. In addition, Lone Star has secured capacity on ETPs recently announced NGL pipeline from Jackson County to Mont Belvieu, Texas.
OUR OPERATIONS. We divide our operations into five business segments:
| Gathering and Processing. We provide wellhead-to-market services to producers of natural gas, which include gathering raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems. |
| Joint Ventures. We own a 49.99% general partner interest in HPC, which owns RIGS, a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. We own a 49.9% interest in MEP, which owns an interstate natural gas pipeline with approximately 500 miles stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama. We own a 30% interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, storage and processing facilities located in the states of Texas, Mississippi and Louisiana. |
| Contract Compression. We own and operate a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. |
| Contract Treating. We own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management to natural gas producers and midstream pipeline companies. |
| Corporate and Others. Our Corporate and Others segment comprises a small interstate pipeline and our corporate offices. |
HOW WE EVALUATE OUR OPERATIONS. Management uses a variety of financial and operational measurements to analyze our performance. We view these measures as important tools for evaluating the success of our operations and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, segment margin, total segment margin, adjusted segment margin, adjusted total segment margin, operating and maintenance expense, EBITDA, and adjusted EBITDA on a segment and company-wide basis.
24
Volumes. We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. Our ability to maintain existing supplies of natural gas and obtain new supplies is affected by (i) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our gathering and processing systems, (ii) our ability to compete for volumes from successful new wells in other areas and (iii) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.
Segment Margin and Total Segment Margin. We define segment margin for the Gathering and Processing and the Corporate and Others segments, as revenues, including service fees, less cost of sales. We calculate our revenues generated from operations less the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees.
We do not record segment margin for the Joint Ventures segment because we record our ownership percentages of the net income in HPC, MEP and Lone Star as income from unconsolidated affiliates in accordance with the equity method of accounting.
We calculate our Contract Compression segment margin as revenues minus direct costs, primarily compressor unit repairs, associated with those revenues.
We calculate our Contract Treating segment margin as revenues minus direct costs associated with those revenues.
We calculate total segment margin as the summation of segment margin of our five segments, less intersegment eliminations.
Adjusted Segment Margin and Adjusted Total Segment Margin. We define adjusted segment margin as segment margin adjusted for non-cash (gains) losses from commodity derivatives. We define adjusted total segment margin as total segment margin adjusted for non-cash (gains) losses from commodity derivatives. Our adjusted total segment margin equals the sum of our operating segments adjusted segment margins or segment margins, including intersegment eliminations. Adjusted segment margin and adjusted total segment margin are included as supplemental disclosures because they are primary performance measures used by management as they represent the results of our revenues and cost of revenues, a key component of our operations.
Revenue Generating Horsepower. Revenue generating horsepower is the primary driver for revenue growth in our Contract Compression segment, and it is also the primary measure for evaluating our operational efficiency. Revenue generating horsepower is the total horsepower that our Contract Compression segment owns and operates for external customers. It does not include horsepower under contract that is not generating revenue or idle horsepower.
Revenue Generating Gallons per Minute (GPM). Revenue generating GPM is the primary driver for revenue growth of our Contract Treating segment. GPM is used as a measure of the treating capacity of an amine plant. Revenue generating GPM is our total GPM under contract less GPM that is not generating revenue.
Operation and Maintenance Expense. Operation and maintenance expense is a separate measure that we use to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating and maintenance expense. These expenses are largely independent of the volumes through our systems but fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenues in calculating segment margin because we separately evaluate commodity volume and price changes in segment margin.
EBITDA and Adjusted EBITDA. We define EBITDA as net income (loss) plus interest expense, net, income tax expense, net and depreciation and amortization expense. We define adjusted EBITDA as EBITDA plus or minus the following:
| non-cash loss (gain) from commodity and embedded derivatives; |
| non-cash unit based compensation; |
| loss (gain) on asset sales, net; |
| loss on debt refinancing; |
| other non-cash (income) expense, net; |
| net income attributable to noncontrolling interest; and |
| the Partnerships interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates. |
25
These measures are used as supplemental measures by our management and by external users of our financial statements such as investors, banks, research analysts and others, to assess:
| financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
| the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and General Partner; |
| our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and |
| the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
Neither EBITDA nor adjusted EBITDA should be considered as an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded partnership.
The following table presents a reconciliation of EBITDA and adjusted EBITDA to net cash flows provided by operating activities and to net income (loss) for the Partnership:
Successor | Predecessor | |||||||||||
Six
Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from January 1, 2010 to May 25, 2010 |
||||||||||
Reconciliation of Adjusted EBITDA to net cash flows provided by (used in) operating activities and net income (loss) |
||||||||||||
Net cash flows provided by (used in) operating activities |
$ | 121,114 | $ | (16,207 | ) | $ | 89,421 | |||||
Add (deduct): |
||||||||||||
Depreciation and amortization, including debt issuance cost amortization and bond premium amortization |
(83,587 | ) | (11,330 | ) | (49,363 | ) | ||||||
Write-off of debt issuance costs |
| | (1,780 | ) | ||||||||
Amortization of excess fair value of unconsolidated affiliates |
(2,923 | ) | (365 | ) | | |||||||
Income from unconsolidated affiliates |
58,898 | 8,486 | 15,872 | |||||||||
Derivative valuation change |
5,826 | (6,921 | ) | (12,004 | ) | |||||||
Loss on assets sales, net |
(181 | ) | (10 | ) | (303 | ) | ||||||
Unit-based compensation expenses |
(1,747 | ) | (137 | ) | (12,070 | ) | ||||||
Trade accounts receivable, accrued revenues and related party receivables |
8,847 | (13,843 | ) | 11,272 | ||||||||
Other current assets |
(964 | ) | (585 | ) | (2,516 | ) | ||||||
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues |
(28,577 | ) | 15,460 | (8,649 | ) | |||||||
Other current liabilities |
2,764 | 20,497 | (22,614 | ) | ||||||||
Distributions received from unconsolidated affiliates |
(50,510 | ) | | (12,446 | ) | |||||||
Other assets and liabilities |
182 | 60 | 234 | |||||||||
|
|
|
|
|
|
|||||||
Net income (loss) |
29,142 | (4,895 | ) | (4,946 | ) | |||||||
Add (deduct): |
||||||||||||
Interest expense, net |
44,696 | 8,109 | 34,679 | |||||||||
Depreciation and amortization expense |
80,739 | 10,995 | 46,084 | |||||||||
Income tax expense |
70 | 245 | 404 | |||||||||
|
|
|
|
|
|
|||||||
EBITDA |
154,647 | 14,454 | 76,221 | |||||||||
Add (deduct): |
||||||||||||
Non-cash (gain) loss from commodity and embedded derivatives |
(5,093 | ) | 5,856 | 11,189 | ||||||||
Non-cash unit-based compensation expense |
1,796 | 113 | 11,925 | |||||||||
Loss on assets sales, net |
181 | 10 | 303 | |||||||||
Income from unconsolidated affiliates, net of amortization |
(55,975 | ) | (8,121 | ) | (15,872 | ) | ||||||
Partnerships ownership interest in HPCs adjusted EBITDA |
38,775 | 5,824 | 21,184 | |||||||||
Partnerships ownership interest in MEPs adjusted EBITDA |
50,513 | 8,424 | | |||||||||
Partnerships ownership interest in Lone Stars adjusted EBITDA |
10,584 | | | |||||||||
Loss on debt refinancing, net |
| | 1,780 | |||||||||
Other (income) expense, net |
(235 | ) | 191 | 2,064 | ||||||||
|
|
|
|
|
|
|||||||
Adjusted EBITDA |
$ | 195,193 | $ | 26,751 | $ | 108,794 | ||||||
|
|
|
|
|
|
26
The following table presents a reconciliation of net income to EBITDA and adjusted EBITDA for HPC and represents 100% of HPCs consolidated results of operations:
Six Months
Ended June 30, |
||||||||
2011 | 2010 | |||||||
Net income |
$ | 60,421 | $ | 44,274 | ||||
Add: |
||||||||
Depreciation and amortization |
16,746 | 14,421 | ||||||
Interest expense, net |
387 | 201 | ||||||
|
|
|
|
|||||
EBITDA |
$ | 77,554 | $ | 58,896 | ||||
Add: |
||||||||
Other expenses, net |
11 | 12 | ||||||
|
|
|
|
|||||
Adjusted EBITDA |
$ | 77,565 | $ | 58,908 | ||||
|
|
|
|
The following table presents a reconciliation of net income to EBITDA and adjusted EBITDA for MEP and represents 100% of MEPs consolidated results of operations:
Six
Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
|||||||
Net income |
$ | 40,686 | $ | 8,068 | ||||
Add: |
||||||||
Depreciation and amortization |
34,775 | 5,383 | ||||||
Interest expense, net |
25,768 | 3,431 | ||||||
|
|
|
|
|||||
EBITDA and Adjusted EBITDA |
$ | 101,229 | $ | 16,882 | ||||
|
|
|
|
The following table presents a reconciliation of net income to EBITDA and adjusted EBITDA for Lone Star and represents 100% of Lone Stars consolidated results of operations:
Period from
Initial Contribution (May 2, 2011) to June 30, 2011 |
||||
Net income |
$ | 27,958 | ||
Add: |
||||
Depreciation and amortization |
7,139 | |||
Other expenses, net |
185 | |||
|
|
|||
EBITDA and Adjusted EBITDA |
$ | 35,282 | ||
|
|
The following tables present a reconciliation of total segment margin and adjusted total segment margin to net income (loss) for the three and six month periods ended June 30, 2011 for the Partnership:
Successor | Predecessor | |||||||||||
Three
Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from April 1, 2010 to May 25, 2010 |
||||||||||
Net income (loss) |
$ | 14,837 | $ | (4,895 | ) | $ | (4,496 | ) | ||||
Add (deduct): |
||||||||||||
Operation and maintenance |
33,996 | 10,402 | 19,315 | |||||||||
General and administrative |
17,551 | 7,104 | 21,809 | |||||||||
Loss on assets sales, net |
153 | 10 | 19 | |||||||||
Depreciation and amortization |
40,503 | 10,545 | 16,889 | |||||||||
Income from unconsolidated affiliates |
(32,167 | ) | (8,121 | ) | (7,959 | ) | ||||||
Interest expense, net |
24,689 | 8,081 | 14,059 | |||||||||
Other income and deductions, net |
(2,641 | ) | 3,521 | 624 | ||||||||
Income tax expense |
102 | 245 | 83 | |||||||||
Discontinued operations |
| (86 | ) | (585 | ) | |||||||
|
|
|
|
|
|
|||||||
Total segment margin |
97,023 | 26,806 | 59,758 | |||||||||
Add: |
||||||||||||
Non-cash loss from commodity derivatives |
2,147 | 2,250 | 3,344 | |||||||||
|
|
|
|
|
|
|||||||
Adjusted total segment margin |
$ | 99,170 | $ | 29,056 | $ | 63,102 | ||||||
|
|
|
|
|
|
27
Successor | Predecessor | |||||||||||||
Six
Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from January 1, 2010 to May 25, 2010 |
||||||||||||
Net income (loss) |
$ | 29,142 | $ | (4,895 | ) | $ | (4,946 | ) | ||||||
Add (deduct): |
||||||||||||||
Operation and maintenance |
67,556 | 10,402 | 47,842 | |||||||||||
General and administrative |
36,660 | 7,104 | 37,212 | |||||||||||
Loss on assets sales, net |
181 | 10 | 303 | |||||||||||
Depreciation and amortization |
80,739 | 10,545 | 41,784 | |||||||||||
Income from unconsolidated affiliates |
(55,975 | ) | (8,121 | ) | (15,872 | ) | ||||||||
Interest expense, net |
44,696 | 8,081 | 34,541 | |||||||||||
Loss on debt refinancing, net |
| | 1,780 | |||||||||||
Other income and deductions, net |
(5,055 | ) | 3,521 | 3,897 | ||||||||||
Income tax expense |
70 | 245 | 404 | |||||||||||
Discontinued operations |
| (86 | ) | 327 | ||||||||||
|
|
|
|
|
|
|||||||||
Total segment margin |
198,014 | 26,806 | 147,272 | |||||||||||
Add: |
||||||||||||||
Non-cash loss from commodity derivatives |
432 | 2,250 | 7,150 | |||||||||||
|
|
|
|
|
|
|||||||||
Adjusted total segment margin |
$ | 198,446 | $ | 29,056 | $ | 154,422 | ||||||||
|
|
|
|
|
|
RESULTS OF OPERATIONS
Three Months Ended June 30, 2011 vs. Combined Three Months Ended June 30, 2010
Successor | Predecessor | |||||||||||||||||||||||
Three Months Ended June 30, 2011 |
Period
from Acquisition (May 26, 2010) to June 30, 2010 |
Period from April 1, 2010 to May 25, 2010 |
Combined Three Months Ended June 30, 2010 |
Change | Percent | |||||||||||||||||||
Total revenues |
$ | 356,498 | $ | 96,980 | $ | 200,265 | $ | 297,245 | $ | 59,253 | 20 | % | ||||||||||||
Cost of sales |
259,475 | 70,174 | 140,507 | 210,681 | (48,794 | ) | 23 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Total segment margin (1) |
97,023 | 26,806 | 59,758 | 86,564 | 10,459 | 12 | % | |||||||||||||||||
Operation and maintenance |
33,996 | 10,402 | 19,315 | 29,717 | (4,279 | ) | 14 | % | ||||||||||||||||
General and administrative |
17,551 | 7,104 | 21,809 | 28,913 | 11,362 | 39 | % | |||||||||||||||||
Loss on asset sales, net |
153 | 10 | 19 | 29 | (124 | ) | 428 | % | ||||||||||||||||
Depreciation and amortization |
40,503 | 10,545 | 16,889 | 27,434 | (13,069 | ) | 48 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Operating income (loss) |
4,820 | (1,255 | ) | 1,726 | 471 | 4,349 | 923 | % | ||||||||||||||||
Income from unconsolidated affiliates |
32,167 | 8,121 | 7,959 | 16,080 | 16,087 | 100 | % | |||||||||||||||||
Interest expense, net |
(24,689 | ) | (8,081 | ) | (14,059 | ) | (22,140 | ) | (2,549 | ) | 12 | % | ||||||||||||
Other income and deductions, net |
2,641 | (3,521 | ) | (624 | ) | (4,145 | ) | 6,786 | 164 | % | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Income (loss) from continuing operations before income taxes |
14,939 | (4,736 | ) | (4,998 | ) | (9,734 | ) | 24,673 | 253 | % | ||||||||||||||
Income tax expense |
102 | 245 | 83 | 328 | 226 | 69 | % | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Net income (loss) from continuing operations |
14,837 | (4,981 | ) | (5,081 | ) | (10,062 | ) | 24,899 | 247 | % | ||||||||||||||
Discontinued operations |
| 86 | 585 | 671 | (671 | ) | 100 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Net income (loss) |
14,837 | (4,895 | ) | (4,496 | ) | (9,391 | ) | 24,228 | 258 | % | ||||||||||||||
Net income attributable to noncontrolling interest |
(293 | ) | (29 | ) | (244 | ) | (273 | ) | (20 | ) | 7 | % | ||||||||||||
|
|
|
|
|
|
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Net income (loss) attributable to Regency Energy Partners LP |
$ | 14,544 | $ | (4,924 | ) | $ | (4,740 | ) | $ | (9,664 | ) | $ | 24,208 | 250 | % | |||||||||
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Gathering and processing segment margin (2) |
$ | 50,495 | $ | 14,373 | $ | 35,195 | $ | 49,568 | $ | 927 | 2 | % | ||||||||||||
Non-cash loss from commodity derivatives |
2,147 | 2,250 | 3,344 | 5,594 | (3,447 | ) | 62 | % | ||||||||||||||||
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Adjusted gathering and processing segment margin |
52,642 | 16,623 | 38,539 | 55,162 | (2,520 | ) | 5 | % | ||||||||||||||||
Contract compression segment margin (3) |
36,973 | 12,488 | 25,326 | 37,814 | (841 | ) | 2 | % | ||||||||||||||||
Contract treating segment margin |
7,701 | | | | 7,701 | 100 | % | |||||||||||||||||
Corporate and others segment margin (2) |
4,762 | 1,943 | 3,031 | 4,974 | (212 | ) | 4 | % | ||||||||||||||||
Intersegment eliminations (3) |
(2,908 | ) | (1,998 | ) | (3,794 | ) | (5,792 | ) | 2,884 | 50 | % | |||||||||||||
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Adjusted total segment margin |
$ | 99,170 | $ | 29,056 | $ | 63,102 | $ | 92,158 | $ | 7,012 | 8 | % | ||||||||||||
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(1) | For a reconciliation of segment margin to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the reconciliation provided above. |
(2) | Segment margin differs from previously disclosed amounts due to the presentation as discontinued operations for the disposition of our east Texas assets, as well as a functional reorganization of our operating segments. |
(3) | Contract Compression segment margin includes intersegment revenues of $2.9 million and $5.8 million for the three months ended June 30, 2011 and June 30, 2010, respectively. These intersegment revenues were eliminated upon consolidation. |
28
Net Income (Loss) Attributable to Regency Energy Partners LP. Our income increased to $14.5 million for the three months ended June 30, 2011 from a net loss of $9.7 million for the combined three months ended June 30, 2010. The major components of this change were as follows:
| $16.1 million increase in income from unconsolidated affiliates from the acquisition of a 30% interest in Lone Star in May 2011 and the acquisition of a 49.9% interest in MEP in May 2010; |
| $11.4 million decrease in general and administrative expense related to the vesting of the outstanding restricted and phantom units that occurred in the second quarter of 2010 upon the change in control resulting from the acquisition of our General Partner; |
| $10.5 million increase in total segment margin primarily from the addition of the Contract Treating segment acquired in September 2010; offset by |
| $13.1 million increase in depreciation and amortization expense primarily related to the completion of various organic growth projects since June 2010 and the increase of property, plant and equipment and intangible amounts resulting from the fair value adjustments upon the change of control resulting from the acquisition of our General Partner in May 2010. |
Adjusted Total Segment Margin. Adjusted total segment margin increased to $99.2 million in the three months ended June 30, 2011 from $92.2 million in the combined three months ended June 30, 2010. The major components of this change were as follows:
| Adjusted Gathering and Processing segment margin decreased to $52.6 million during the three months ended June 30, 2011 from $55.2 million for the combined three months ended June 30, 2010 primarily due to lower realized commodity prices and lower production in north Louisiana, offset by volume growth in the Eagle Ford Shale and west Texas. Total Gathering and Processing throughput increased to 1,063,000 MMBtu/d during the three months ended June 30, 2011 from 1,002,000 MMBtu/d during the three months ended June 30, 2010. Total NGL gross production increased to 28,000 Bbls/d during the three months ended June 30, 2011 from 25,000 Bbls/d during the three months ended June 30, 2010; |
| Contract Compression segment margin decreased to $37 million in the three months ended June 30, 2011 from $37.8 million in the |