e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2007
OR
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 0001-338613
REGENCY ENERGY PARTNERS LP
(Exact name of registrant as specified in its charter)
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DELAWARE
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16-1731691 |
(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.) |
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1700 PACIFIC AVENUE, SUITE 2900 |
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DALLAS, TX
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75201 |
(Address of principal executive offices)
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(Zip Code) |
(214) 750-1771
(Registrants telephone number, including area code)
NONE
(Former name, former address and former fiscal year, if changed since last report.)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. þ Yes o No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in
Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o Accelerated filer o Non-accelerated filer þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). o Yes þ No
The issuer had 28,576,981 common units and 19,103,896 subordinated units outstanding as of May 8,
2007.
Cautionary Statement about Forward-Looking Statements
Certain matters discussed in this report include forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
Forward-looking statements are identified as any statement that does not relate strictly to
historical or current facts. Statements using words such as anticipate, believe, intend,
project, plan, expect, continue, estimate, goal, forecast, may or similar
expressions help identify forward-looking statements. Although we believe our forward-looking
statements are based on reasonable assumptions and current expectations and projections about
future events, we can not give assurances that such expectations will prove to be correct.
Forward-looking statements are subject to a variety of risks, uncertainties and assumptions
including without limitation the following:
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changes in laws and regulations impacting the midstream sector of the natural gas industry; |
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the level of creditworthiness of our counterparties; |
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our ability to access the debt and equity markets; |
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our use of derivative financial instruments to hedge commodity and interest rate risks; |
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the amount of collateral required to be posted from time to time in our transactions; |
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changes in commodity prices, interest rates and demand for our services; |
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weather and other natural phenomena; |
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industry changes including the impact of consolidations and changes in competition; |
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our ability to obtain required approvals for construction or modernization of our
facilities and the timing of production from such facilities; and |
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the effect of accounting pronouncements issued periodically by accounting standard
setting boards. |
If one or more of these risks or uncertainties materialize, or if underlying assumptions prove
incorrect, our actual results may differ materially from those anticipated, estimated, projected or
expected.
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.
Part I Financial Information
Item 1. Financial Statements
Regency Energy Partners LP
Condensed Consolidated Balance Sheets
Unaudited
(In thousands except unit data)
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March 31, 2007 |
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December 31, 2006 |
|
ASSETS |
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Current Assets: |
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|
|
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|
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|
Cash and cash equivalents |
|
$ |
8,504 |
|
|
$ |
9,139 |
|
Restricted cash |
|
|
5,847 |
|
|
|
5,782 |
|
Accounts receivable, net of allowance of $94 in 2007 and $181 in 2006 |
|
|
99,310 |
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|
96,993 |
|
Related party receivables |
|
|
397 |
|
|
|
755 |
|
Assets from risk management activities |
|
|
22 |
|
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|
2,126 |
|
Other current assets |
|
|
4,681 |
|
|
|
5,279 |
|
|
|
|
|
|
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|
Total current assets |
|
|
118,761 |
|
|
|
120,074 |
|
|
|
|
|
|
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|
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Property, plant and equipment |
|
|
|
|
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Gas plants and buildings |
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103,685 |
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|
103,490 |
|
Gathering and transmission systems |
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|
540,821 |
|
|
|
529,776 |
|
Other property, plant and equipment |
|
|
76,106 |
|
|
|
73,861 |
|
Construction-in-progress |
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|
109,641 |
|
|
|
85,277 |
|
|
|
|
|
|
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|
Total property, plant and equipment |
|
|
830,253 |
|
|
|
792,404 |
|
Less accumulated depreciation |
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|
(68,133 |
) |
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|
(58,370 |
) |
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Property, plant and equipment, net |
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|
762,120 |
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|
734,034 |
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Other assets: |
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Intangible assets, net of amortization of $5,669 in 2007 and $4,676 in 2006 |
|
|
75,930 |
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|
76,923 |
|
Long-term assets from risk management activities |
|
|
111 |
|
|
|
1,674 |
|
Other, net of amortization of debt issuance costs of $1,505 in 2007 and $946 in 2006 |
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|
17,085 |
|
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|
17,212 |
|
Investments in unconsolidated subsidiaries |
|
|
|
|
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|
5,616 |
|
Goodwill |
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|
57,552 |
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|
57,552 |
|
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|
|
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Total other assets |
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|
150,678 |
|
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|
158,977 |
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|
|
|
|
|
|
|
|
|
|
|
|
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TOTAL ASSETS |
|
$ |
1,031,559 |
|
|
$ |
1,013,085 |
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|
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LIABILITIES & PARTNERS CAPITAL |
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Current Liabilities: |
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Accounts payable and accrued liabilities |
|
$ |
109,053 |
|
|
$ |
117,254 |
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Related party payables |
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|
389 |
|
|
|
280 |
|
Escrow payable |
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|
5,848 |
|
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|
5,783 |
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Accrued taxes payable |
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|
2,961 |
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|
2,758 |
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Liabilities from risk management activities |
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|
9,511 |
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|
3,647 |
|
Interest payable |
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|
14,916 |
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|
2,998 |
|
Other current liabilities |
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|
1,090 |
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|
2,594 |
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|
|
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Total current liabilities |
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|
143,768 |
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|
|
135,314 |
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|
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|
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Long-term liabilities from risk management activities |
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|
2,989 |
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|
|
145 |
|
Other long-term liabilities |
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|
1,350 |
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|
269 |
|
Long-term debt |
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|
698,100 |
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664,700 |
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Partners Capital: |
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Common units (29,915,745 and 21,969,480 units authorized; 27,824,914 and 19,620,396 units issued and
outstanding at March 31, 2007 and December 31, 2006) |
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|
155,613 |
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|
42,192 |
|
Class B common units (5,173,189 units authorized, issued and outstanding at December 31, 2006) |
|
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|
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|
60,671 |
|
Class C common units (2,857,143 units authorized, issued and outstanding at December 31, 2006) |
|
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59,992 |
|
Subordinated units (19,103,896 units authorized, issued and outstanding at March 31, 2007 and
December 31, 2006) |
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|
35,988 |
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|
43,240 |
|
General partner interest |
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|
5,231 |
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|
5,543 |
|
Accumulated other comprehensive income (loss) |
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|
(11,480 |
) |
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|
1,019 |
|
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|
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|
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Total partners capital |
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|
185,352 |
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|
212,657 |
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TOTAL LIABILITIES AND PARTNERS CAPITAL |
|
$ |
1,031,559 |
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|
$ |
1,013,085 |
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|
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See accompanying notes to unaudited condensed consolidated financial statements
Regency Energy Partners LP
Condensed Consolidated Statements of Operations
Unaudited
(In thousands except unit data and per unit data)
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Three Months Ended |
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|
March 31, 2007 |
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|
March 31, 2006 |
|
REVENUES |
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Gas sales |
|
$ |
167,384 |
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|
$ |
158,472 |
|
NGL sales |
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|
63,541 |
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|
|
56,136 |
|
Gathering, transportation and other fees, including related party amounts of $353 in 2007 and $519 in 2006 |
|
|
19,878 |
|
|
|
12,704 |
|
Net realized and unrealized loss from risk management activities |
|
|
(85 |
) |
|
|
(1,657 |
) |
Other |
|
|
5,710 |
|
|
|
5,611 |
|
|
|
|
|
|
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Total revenues |
|
|
256,428 |
|
|
|
231,266 |
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|
|
|
|
|
|
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OPERATING COSTS AND EXPENSES |
|
|
|
|
|
|
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|
Cost of gas and liquids, including related party amounts of $5,418 in 2007 and $513 in 2006 |
|
|
211,937 |
|
|
|
196,736 |
|
Operation and maintenance |
|
|
10,925 |
|
|
|
9,445 |
|
General and administrative |
|
|
6,851 |
|
|
|
5,416 |
|
Loss on sale of assets |
|
|
1,808 |
|
|
|
|
|
Management services termination fee |
|
|
|
|
|
|
9,000 |
|
Depreciation and amortization |
|
|
11,427 |
|
|
|
9,169 |
|
|
|
|
|
|
|
|
Total operating costs and expenses |
|
|
242,948 |
|
|
|
229,766 |
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME |
|
|
13,480 |
|
|
|
1,500 |
|
|
|
|
|
|
|
|
|
|
Interest expense, net |
|
|
(14,885 |
) |
|
|
(8,001 |
) |
Other income and deductions, net |
|
|
110 |
|
|
|
182 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
NET LOSS |
|
$ |
(1,295 |
) |
|
$ |
(6,319 |
) |
|
|
|
|
|
|
|
|
|
Less: Net income from January 1-31, 2006 |
|
|
|
|
|
|
1,564 |
|
|
|
|
|
|
|
|
Net loss for partners |
|
$ |
(1,295 |
) |
|
$ |
(7,883 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest |
|
|
(26 |
) |
|
|
(158 |
) |
|
|
|
|
|
|
|
Limited partners interest |
|
$ |
(1,269 |
) |
|
$ |
(7,725 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted earnings per unit: |
|
|
|
|
|
|
|
|
Net loss allocated to common units |
|
$ |
(635 |
) |
|
$ |
(3,402 |
) |
Weighted average number of common units outstanding |
|
|
23,252,059 |
|
|
|
19,103,896 |
|
Loss per common unit |
|
$ |
(0.03 |
) |
|
$ |
(0.18 |
) |
Distributions declared per unit |
|
$ |
0.38 |
|
|
$ |
0.2217 |
|
|
|
|
|
|
|
|
|
|
Net loss allocated to subordinated units |
|
|
(634 |
) |
|
$ |
(3,402 |
) |
Weighted average number of subordinated units outstanding |
|
|
19,103,896 |
|
|
|
19,103,896 |
|
Loss per subordinated unit |
|
$ |
(0.03 |
) |
|
|
(0.18 |
) |
Distributions declared per unit |
|
$ |
0.38 |
|
|
$ |
0.2217 |
|
|
|
|
|
|
|
|
|
|
Net loss allocated to Class B common units |
|
$ |
|
|
|
$ |
(921 |
) |
Weighted average number of Class B common units outstanding |
|
|
2,644,074 |
|
|
|
5,173,189 |
|
Loss per Class B common unit |
|
$ |
|
|
|
$ |
(0.18 |
) |
Distributions declared per unit |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
Net loss allocated to Class C common units |
|
$ |
|
|
|
$ |
|
|
Weighted average number of Class C common units outstanding |
|
|
1,238,095 |
|
|
|
|
|
Loss per Class C common unit |
|
$ |
|
|
|
$ |
|
|
Distributions declared per unit |
|
$ |
|
|
|
$ |
|
|
See accompanying notes to unaudited condensed consolidated financial statements
Regency Energy Partners LP
Condensed Consolidated Statement of Partners Capital
Unaudited
(In thousands except unit data)
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|
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Accumulated |
|
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|
|
Units |
|
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|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
General |
|
|
Other |
|
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|
|
|
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|
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|
Common |
|
|
Class B |
|
|
Class C |
|
|
Subordinated |
|
|
Partner |
|
|
Comprehensive |
|
|
|
|
|
|
Common |
|
|
Class B |
|
|
Class C |
|
|
Subordinated |
|
|
Unitholders |
|
|
Unitholders |
|
|
Unitholders |
|
|
Unitholders |
|
|
Interest |
|
|
Income (Loss) |
|
|
Total |
|
Balance December 31, 2006 |
|
|
19,620,396 |
|
|
|
5,173,189 |
|
|
|
2,857,143 |
|
|
|
19,103,896 |
|
|
$ |
42,192 |
|
|
$ |
60,671 |
|
|
$ |
59,992 |
|
|
$ |
43,240 |
|
|
$ |
5,543 |
|
|
$ |
1,019 |
|
|
$ |
212,657 |
|
Conversion of Class B and C to common units |
|
|
8,030,332 |
|
|
|
(5,173,189 |
) |
|
|
(2,857,143 |
) |
|
|
|
|
|
|
120,663 |
|
|
|
(60,671 |
) |
|
|
(59,992 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of restricted common units |
|
|
191,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeitures of restricted common units |
|
|
(20,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of common unit options |
|
|
3,186 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit based compensation expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
653 |
|
|
|
|
|
|
|
|
|
|
|
450 |
|
|
|
|
|
|
|
|
|
|
|
1,103 |
|
General Partner contributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
6 |
|
Partner distributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,260 |
) |
|
|
|
|
|
|
|
|
|
|
(7,068 |
) |
|
|
(292 |
) |
|
|
|
|
|
|
(14,620 |
) |
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(635 |
) |
|
|
|
|
|
|
|
|
|
|
(634 |
) |
|
|
(26 |
) |
|
|
|
|
|
|
(1,295 |
) |
Net hedging activity
reclassified to earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(54 |
) |
|
|
(54 |
) |
Net change in fair value
of cash flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,445 |
) |
|
|
(12,445 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance March 31, 2007 |
|
|
27,824,914 |
|
|
|
|
|
|
|
|
|
|
|
19,103,896 |
|
|
$ |
155,613 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
35,988 |
|
|
$ |
5,231 |
|
|
$ |
(11,480 |
) |
|
$ |
185,352 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated financial statements
Regency Energy Partners LP
Consdensed Consolidated Statements of Comprehensive Loss
Unaudited
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, 2007 |
|
|
March 31, 2006 |
|
Net loss |
|
$ |
(1,295 |
) |
|
$ |
(6,319 |
) |
Hedging losses reclassified to earnings |
|
|
(54 |
) |
|
|
813 |
|
Net change in fair value of cash flow hedges |
|
|
(12,445 |
) |
|
|
4,427 |
|
|
|
|
|
|
|
|
Comprehensive loss |
|
$ |
(13,794 |
) |
|
$ |
(1,079 |
) |
|
|
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated financial statements
Regency Energy Partners LP
Condensed Consolidated Statement of Cash Flows
Unaudited
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, 2007 |
|
|
March 31, 2006 |
|
OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(1,295 |
) |
|
$ |
(6,319 |
) |
Adjustments
to reconcile net loss to net cash flows provided by (used in) operating activities: |
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
11,986 |
|
|
|
9,318 |
|
Equity income |
|
|
(43 |
) |
|
|
(91 |
) |
Risk management portfolio valuation changes |
|
|
(124 |
) |
|
|
(191 |
) |
Loss on sale of assets |
|
|
1,808 |
|
|
|
|
|
Unit based compensation expenses |
|
|
1,103 |
|
|
|
314 |
|
Cash flow changes in current assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(1,959 |
) |
|
|
16,938 |
|
Other current assets |
|
|
598 |
|
|
|
921 |
|
Accounts payable and accrued liabilities |
|
|
5,220 |
|
|
|
(23,535 |
) |
Accrued taxes payable |
|
|
203 |
|
|
|
273 |
|
Interest payable |
|
|
11,918 |
|
|
|
|
|
Other current liabilities |
|
|
(1,504 |
) |
|
|
12 |
|
Other assets |
|
|
(441 |
) |
|
|
2,515 |
|
Other liabilities |
|
|
|
|
|
|
(626 |
) |
|
|
|
|
|
|
|
Net cash flows provided by (used in) operating activities |
|
|
27,470 |
|
|
|
(471 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(47,501 |
) |
|
|
(30,454 |
) |
Investments in unconsolidated subsidiaries |
|
|
|
|
|
|
(57 |
) |
Acquisition of investment in unconsolidated subsidiary |
|
|
(5,000 |
) |
|
|
133 |
|
Proceeds from sale of assets |
|
|
5,610 |
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows used in investing activities |
|
|
(46,891 |
) |
|
|
(30,378 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
Net borrowings under revolving credit facilities |
|
|
33,400 |
|
|
|
22,125 |
|
Debt issuance costs |
|
|
|
|
|
|
(151 |
) |
Proceeds from IPO, net of issuance costs |
|
|
|
|
|
|
252,734 |
|
Capital reimbursement to HM Capital Partners |
|
|
|
|
|
|
(243,757 |
) |
Proceeds from exercise of over allotment option |
|
|
|
|
|
|
26,163 |
|
Over allotment option proceeds to HM Capital Partners |
|
|
|
|
|
|
(26,163 |
) |
Partner contributions |
|
|
6 |
|
|
|
|
|
Partner distributions |
|
|
(14,620 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash flows provided by financing activities |
|
|
18,786 |
|
|
|
30,951 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
(635 |
) |
|
|
102 |
|
Cash and cash equivalents at beginning of period |
|
|
9,139 |
|
|
|
3,686 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
8,504 |
|
|
$ |
3,788 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information |
|
|
|
|
|
|
|
|
Interest paid, net of amounts capitalized |
|
$ |
2,540 |
|
|
$ |
6,251 |
|
Non-cash capital expenditures in accounts payable |
|
|
10,509 |
|
|
|
15,069 |
|
Non-cash capital expenditures for consolidation of investment
in previously unconsolidated subsidiary |
|
|
5,650 |
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated financial statements
Regency Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements
1. Organization and Summary of Significant Accounting Policies
Organization and Basis of Presentation. The unaudited condensed consolidated financial
statements presented herein contain the results of Regency Energy Partners LP, a Delaware limited
partnership (Partnership), and its predecessor, Regency Gas Services LLC (Predecessor). The
Partnership was formed on September 8, 2005; on February 3, 2006, in conjunction with its initial
public offering of securities (IPO), the Predecessor was converted to a limited partnership,
Regency Gas Services LP (RGS) and became a wholly owned subsidiary of the Partnership. The
Partnership and its subsidiaries are engaged in the business of gathering, treating, processing,
transporting, and marketing natural gas and natural gas liquids (NGLs). On August 15, 2006, the
Partnership, through RGS, acquired all the outstanding equity of TexStar Field Services, L.P. and
its general partner, TexStar GP, LLC (the TexStar Acquisition), from HMTF Gas Partners II, L.P.
(HMTF Gas Partners), an affiliate of HM Capital Partners LLC (HM Capital Partners). Hicks Muse
Equity Fund V, L.P. (Fund V) and its affiliates, through HM Capital Partners, control Regency GP
LP, the general partner of the Partnership (the General Partner). Fund V also controls HMTF Gas
Partners through HM Capital Partners. Because the TexStar Acquisition was a transaction between
commonly controlled entities, the Partnership is required to account for the TexStar Acquisition in
a manner similar to a pooling of interests. Information included in these financial statements for
periods presented prior the consummation of the TexStar Acquisition has been adjusted to reflect
the TexStar acquisition.
The accompanying unaudited condensed consolidated financial statements include the assets,
liabilities, results of operations and cash flows of the Partnership and its wholly owned
subsidiaries. The Partnership operates and manages its business as two reportable segments: a)
gathering and processing, and b) transportation.
The unaudited financial information as of, and for the three months ended, March 31, 2007 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, 2006. 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 accounting principles generally accepted in the United States of America
(GAAP). All intercompany items and transactions have been eliminated in consolidation. Certain
information and footnote disclosures normally included in annual consolidated financial statements
prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the
Securities and Exchange Commission. The Partnership reclassified interest payable at December 31,
2006 to conform to the current year presentation.
Use of Estimates. The unaudited condensed consolidated financial statements have been
prepared in conformity with GAAP and, of necessity, include the use of estimates and assumptions by
management. Actual results could differ from these estimates.
Intangible Assets. The total gross carrying amount of intangible assets that were subject to
amortization was $81,599,000 at March 31, 2007 and December 31, 2006. Aggregate amortization
expense for the three months ended March 31, 2007 and 2006 was $993,000 and $468,000, respectively.
Recently Issued Accounting Standards. In July 2006, the Financial Accounting Standards Board
(FASB) issued FIN No. 48 Accounting for Uncertainty in Income Taxes An Interpretation of FASB
Statement 109, which clarifies the accounting for uncertainty in income taxes recognized in
financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes and
is effective for fiscal years beginning after December 15, 2006. FIN 48 prescribes a recognition
threshold and measurement attribute for the financial statement recognition and measurement of a
tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on
derecognition, classification, interest and penalties, accounting in interim periods, disclosure
and transition. The adoption of FIN 48 did not have a material impact on the Partnerships
consolidated results of operations, cash flows or financial position.
In September 2006, the FASB issued Statement of Financial Accounting Standard (SFAS) No.
157, Fair Value Measurements (SFAS No. 157), which provides guidance for using fair value to
measure assets and liabilities. SFAS 157 applies whenever another standard requires (or permits)
assets or liabilities to be measured at fair value. This standard does not expand the use of fair
value to any new circumstances. SFAS No. 157 is effective for financial statements issued for
fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The
Partnership is currently evaluating the potential effects on its financial position, results of
operations or cash flows of the adoption of this standard.
In January 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and
Financial Liabilities, Including an Amendment of FASB Statement No. 115 (SFAS 159), which
permits entities to measure many financial instruments and certain other assets and liabilities at
fair value on an instrument-by-instrument basis. SFAS No. 159 is effective for fiscal years
beginning after November 15, 2007. The Partnership is currently evaluating the potential effects
on its financial position, results of operations or cash flows of the adoption of this standard.
2. Loss per Limited Partner Unit
The following data show the amounts used in computing limited partner loss per unit.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, 2007 |
|
|
March 31, 2006 |
|
|
|
(in thousands except unit data and per unit data) |
|
Net loss for partners |
|
$ |
(1,295 |
) |
|
$ |
(7,883 |
) |
Adjustments: |
|
|
|
|
|
|
|
|
General partners allocation of prior year losses |
|
|
|
|
|
|
|
|
General partners interest |
|
|
(26 |
) |
|
|
(158 |
) |
|
|
|
|
|
|
|
Limited partners interest in net loss |
|
$ |
(1,269 |
) |
|
$ |
(7,725 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss allocated to common unitholders |
|
$ |
(635 |
) |
|
$ |
(3,402 |
) |
Weighted average common limited partner units basic and diluted |
|
|
23,252,059 |
|
|
|
19,103,896 |
|
Common limited partners basic and diluted loss per unit |
|
$ |
(0.03 |
) |
|
$ |
(0.18 |
) |
|
|
|
|
|
|
|
|
|
Net loss allocated to subordinated unitholders |
|
$ |
(634 |
) |
|
$ |
(3,402 |
) |
Weighted average subordinated limited partner units basic and diluted |
|
|
19,103,896 |
|
|
|
19,103,896 |
|
Subordinated limited partners basic and diluted loss per unit |
|
$ |
(0.03 |
) |
|
$ |
(0.18 |
) |
|
|
|
|
|
|
|
|
|
Net loss allocated to Class B unitholders |
|
$ |
|
|
|
$ |
(921 |
) |
Weighted average Class B common units outstanding * |
|
|
2,644,074 |
|
|
|
5,173,189 |
|
Class B common limited partners basic and diluted loss per unit |
|
$ |
|
|
|
$ |
(0.18 |
) |
|
|
|
|
|
|
|
|
|
Net loss allocated to Class C unitholders |
|
$ |
|
|
|
$ |
|
|
Weighted average Class C common units outstanding * |
|
|
1,238,095 |
|
|
|
|
|
Class C common limited partners basic and diluted loss per unit |
|
$ |
|
|
|
$ |
|
|
|
|
|
* |
|
Converted into common units prior to the end of March 31, 2007. |
Loss per unit for the three months ended March 31, 2006 reflects only the two months since the
closing of the Partnerships IPO on February 3, 2006. For convenience, January 31, 2006 has been
used as the date of the change in ownership. Accordingly, results for January 2006 have been
excluded from the calculation of loss per unit. Potentially dilutive units related to the
Partnerships long-term incentive plan of 884,866 and 654,000 common unit options and 687,500 and
362,500 restricted common units have been excluded from diluted loss per unit as the effect is
antidilutive for the three months ended March 31, 2007 and 2006 as the Partnership reported a net
loss. Furthermore, while the non-vested (or restricted) units are deemed to be outstanding for
legal purposes, they have been excluded from the calculation of basic loss per unit in accordance
with SFAS No. 128.
In accordance with SFAS No. 128, the Partnership allocates net income or loss to each class of
equity security in
proportion to the amount of distributions earned during that period. Since the
Class B common units were deemed to be outstanding for the three months ended March 31, 2006, a
portion of net loss was allocated to this class of equity because they were not expressly
prohibited from receiving distributions. The Partnership Agreement requires that the general
partner shall receive a 100 percent allocation of income until its capital account is made whole
for all of the net losses allocated to it in prior tax years.
3. Acquisitions and Dispositions
Palafox Joint Venture. The Partnership acquired the outstanding interest in the Palafox Joint
Venture not owned by it (50 percent) for $5,000,000 effective
February 1, 2007. Including the net book value of $5,057,000
immediately prior to its acquisition, the Partnership
allocated $10,057,000 to gathering and transmission systems
($9,464,000) and to working capital accounts ($593,000) in the three
months ended March 31, 2007.
South Texas Assets. The Partnership sold selected non-core pipelines, related rights of way
and contracts located in south Texas for $5,340,000 on March 31, 2007 and recorded a one-time
charge of $1,808,000.
TexStar Acquisition. Since the Partnerships acquisition of TexStar is a transaction between
commonly controlled entities, the Partnership accounted for the TexStar Acquisition in a manner
similar to a pooling of interests. As a result, the historical financial statements of the
Partnership and TexStar have been combined to reflect the historical operations, financial position
and cash flows from the date common control began (December 1, 2004) forward. The following table
presents the revenues and net loss for the previously separate entities and the combined amounts
for the three months ended March 31, 2006 presented in these unaudited condensed consolidated
financial statements.
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, 2006 |
|
|
|
(in thousands) |
|
Revenues |
|
|
|
|
Regency Energy Partners |
|
$ |
201,475 |
|
TexStar Field Services |
|
|
29,791 |
|
|
|
|
|
Combined |
|
|
231,266 |
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
|
|
Regency Energy Partners |
|
|
(6,270 |
) |
TexStar Field Services |
|
|
(49 |
) |
|
|
|
|
Combined |
|
$ |
(6,319 |
) |
|
|
|
|
4. Risk Management Activities
As of March 31, 2007, the Partnerships hedging positions accounted for as cash flow hedges
reduce exposure to variability of future commodity prices through 2009. The net fair value of the
Partnerships risk management activities constituted a liability of $12,367,000 as of March 31,
2007. The Partnership expects to reclassify $9,046,000 of hedging losses into earnings from other
comprehensive income (loss) in the next twelve months. The Partnership calculated an immaterial
amount of ineffectiveness for certain hedges and therefore recorded no amounts to the statement of
operations for hedge ineffectiveness for any period presented.
5. Long-Term Debt
Long-term debt obligations of the Partnership are as follows:
|
|
|
|
|
|
|
|
|
|
|
March 31, 2007 |
|
|
December 31, 2006 |
|
|
|
(in thousands) |
|
Senior notes |
|
$ |
550,000 |
|
|
$ |
550,000 |
|
Term loans |
|
|
50,000 |
|
|
|
50,000 |
|
Revolving loans |
|
|
98,100 |
|
|
|
64,700 |
|
|
|
|
|
|
|
|
Total |
|
|
698,100 |
|
|
|
664,700 |
|
Less: current portion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
$ |
698,100 |
|
|
$ |
664,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Availability |
|
|
|
|
|
|
|
|
Total credit facility limit |
|
$ |
300,000 |
|
|
$ |
300,000 |
|
Term loans |
|
|
(50,000 |
) |
|
|
(50,000 |
) |
Revolver loans |
|
|
(98,100 |
) |
|
|
(64,700 |
) |
Letters of credit |
|
|
(12,003 |
) |
|
|
(5,183 |
) |
|
|
|
|
|
|
|
Total |
|
$ |
139,897 |
|
|
$ |
180,117 |
|
|
|
|
|
|
|
|
The outstanding balances of term debt and revolver debt under the credit facility bear
interest at LIBOR plus a margin or Alternative Base Rate (equivalent to the US prime lending rate)
plus a margin, or a combination of both. The weighted average interest rates for the revolving and
term loan facilities, including interest rate swap settlements, commitment fees, and amortization
of debt issuance costs were 8.78 percent and 7.17 percent for the three months ended March 31, 2007
and 2006, respectively. The outstanding balances of the senior notes bear interest at a fixed rate
of 8.375 percent. At March 31, 2007, the Partnership was in compliance with the covenants of the
credit facility and senior notes.
The Partnership and Regency Energy Finance Corp. (Finance Corp), a wholly-owned subsidiary
of RGS, are co-issuers of the senior notes. Finance Corp. does not have any operations of any kind
and will not have any revenue other than as may be incidental as a co-issuer of the senior notes.
Since the Partnership has no independent operations, the guarantees are full and unconditional and
joint and several and there are no subsidiaries of the Partnership that do not guarantee the senior
notes, the Partnership has not included condensed consolidated financial information of guarantors
of the senior notes.
6. Commitments and Contingencies
Legal. Blackbrush Oil & Gas LLC, owned by an affiliate of HM Capital that was the seller in our
acquisition of TexStar Field Services, L.P., and certain of its subsidiaries are defendants in a
wrongful death action styled Takas v. Strait Energy Services LLC et al. brought in state district
court in Jim Wells County, Texas. The claim for both actual and punitive damages is made on behalf
of the wife of the driver of a tractor trailer truck who was killed when the truck was struck by a
train at a railway crossing. The truck was owned by a subcontractor working on, and was enroute
to, a construction site relating to a pipeline owned by an entity that was then a subsidiary of
TexStar. This accident occurred on July 15, 2005, prior to our acquisition of TexStar on August
15, 2006. We have been advised by representatives of Blackbrush that the entity that owned the
pipeline, which is now our subsidiary (Regency Frio NewLine LP), is likely to be named as a
defendant in the litigation as a result of Blackbrushs reply to the complaint. We have notified
our insurance carrier regarding this matter, and we do not expect it to have a material adverse
effect on our financial condition or our results of operations.
The
Partnership is involved in various other claims and lawsuits incidental to its business.
In the opinion of management, these claims and lawsuits in the aggregate will not have a material
adverse effect on the Partnerships business, financial condition, results of operations or cash
flows.
Escrow Payable. At March 31, 2007, $5,848,000 remained in escrow pending the completion by El
Paso Field Services, LP (El Paso) of environmental remediation projects pursuant to the purchase
and sale agreement (El Paso PSA) related to the assets in north Louisiana and in the
mid-continent area. In the El Paso PSA, El Paso indemnified the Predecessors predecessor,
(Regency LLC Predecessor), against losses arising from pre-closing and known environmental
liabilities subject to a limit of $84,000,000 and subject to certain deductible limits. Upon
completion of a Phase II environmental study, Regency LLC Predecessor notified El Paso of
remediation obligations amounting to $1,800,000 with respect to known environmental matters and
$3,600,000 with respect to pre-closing environmental liabilities. Upon satisfactory completion of
the remediation by El Paso, the amount held in escrow will be released. These contractual rights
of Regency LLC Predecessor were continued by the Partnership.
Environmental. Waha Phase I. A Phase I environmental study was performed on the Waha assets
in connection with the pre-acquisition due diligence process in 2004. Most of the identified
environmental contamination had either been remediated or was being remediated by the previous
owners or operators of the properties. The estimated potential environmental remediation costs at
specific locations were $1,900,000 to $3,100,000. No governmental agency has required that the
Partnership undertakes these remediation efforts. Management believes that the likelihood that it
will be liable for any significant potential remediation liabilities identified in the study is
remote. Separately, the Partnership
acquired an environmental pollution liability insurance policy
in connection with the acquisition to cover any undetected
or unknown pollution discovered in the future. The policy covers clean-up costs and damages
to third parties, and has a 10-year term (expiring 2014) with a $10,000,000 limit subject to
certain deductibles.
Regulatory Environment. In August 2005, Congress enacted and the President signed the Energy
Policy Act of 2005. With respect to the oil and gas industry, the new legislation focuses on the
exploration and production sector, interstate pipelines, and refinery facilities. In many cases,
the Act requires action by various government agencies over the near to mid-term. Management is
unable to determine what impact, if any, the Act will have on its operations and cash flows.
7. Related Party Transactions
BlackBrush Oil & Gas, LP (BBOG), an affiliate of the Partnership, is a natural gas producer
on the Partnerships gas gathering and processing system. At the time of the Partnerships
acquisition of TexStar, BBOG entered into an agreement providing for the long term dedication of
the production from its leases. BlackBrush Energy, Inc., a wholly owned subsidiary of HM Capital,
subleases office space to the Partnership for which it paid $37,000 in the three months ended March
31, 2007.
During the three months ended March 31, 2007 and 2006, the Partnership generated related party
revenues of $353,000 and $519,000 on transportation and compression of natural gas for BBOG. The
Partnership incurred related party expenses of $5,418,000 and $513,000 for the three months ended
March 31, 2007 and 2006. As of March 31, 2007 and December 31, 2006, the Partnerships related
party accounts receivable balances from BBOG were $397,000 and $755,000, respectively. Related
party payables to BBOG were $389,000 and $280,000 as of March 31, 2007 and December 31, 2006,
respectively.
The employees operating the assets of the Partnership and its subsidiaries and all those
providing staff or support services are employees of Regency GP LLC, the Partnerships managing
general partner. Pursuant to the Partnership Agreement, the managing general partner receives a
monthly reimbursement for all direct and indirect expenses that it incurs on behalf of the
Partnership. Reimbursements of $6,049,000 and $2,876,000 were recorded in the Partnerships
financial statements during three months ended March 31, 2007 and 2006 as operating expenses or
general and administrative expenses, as appropriate.
The
Partnership made cash distributions of $7,934,000 and $4,752,000 during the three months
ended March 31, 2007 and 2006 to HM Capital Partners and affiliates as a result of their ownership
of a portion of the Partnerships common and subordinated units, and their ownership of the general
partner interest.
Concurrent with the closing of the Partnerships IPO in three months ended March 31, 2006, the
Partnership paid $9,000,000 to an affiliate of HM Capital Partners to terminate a management
services contract with a remaining tenor of 9 years.
8. Segment Information
The Partnership has two reportable segments: i) gathering and processing and ii)
transportation. Gathering and processing involves the collection of raw natural gas from producer
wells across the five operating regions aggregated for segment reporting purposes and
transportation of it to a treating plant where water and other impurities such as hydrogen sulfide
and carbon dioxide are removed. Treated gas is then processed to remove the natural gas liquids.
The treated and processed natural gas then is transported to market separately from the natural gas
liquids. The Partnership aggregates the results of its gathering and processing activities across
five geographic regions into a single reporting segment.
The transportation segment uses pipelines to transport natural gas from receipt points on its
system to interconnections with larger pipelines or trading hubs and other markets. The
Partnership performs transportation services for shipping customers under firm or interruptible
arrangements. In either case, revenues are primarily fee based and involve minimal direct exposure
to commodity price fluctuations. The Partnership also purchases natural gas at the inlets to the
pipeline and sells this gas at its outlets. The north Louisiana intrastate pipeline operated by
this segment serves the Partnerships gathering and processing facilities in the same area and
those transactions create the
intersegment revenues shown in the table below.
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 is defined as total revenues, including service fees, less cost of gas and liquids.
Management believes segment margin is an important measure because it is directly related to
volumes and commodity price changes. Operation and maintenance expenses are a separate measure
used by management 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 operation and maintenance expenses. These expenses are largely independent
of the volume throughput but fluctuate depending on the activities performed during a specific
period. The Partnership does not deduct operation and maintenance expenses from total revenues in
calculating segment margin because management separately evaluates commodity volume and price
changes in segment margin.
Results for each statement of operations period, together with amounts related to balance
sheets for each segment, are shown below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and |
|
|
|
|
|
|
|
|
|
|
Processing |
|
Transportation |
|
Corporate |
|
Eliminations |
|
Total |
|
|
(in thousands) |
External Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended March 31, 2007 |
|
$ |
177,119 |
|
|
$ |
79,309 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
256,428 |
|
For the three months ended March 31, 2006 |
|
|
163,866 |
|
|
|
67,400 |
|
|
|
|
|
|
|
|
|
|
|
231,266 |
|
Intersegment Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended March 31, 2007 |
|
|
|
|
|
|
14,818 |
|
|
|
|
|
|
|
(14,818 |
) |
|
|
|
|
For the three months ended March 31, 2006 |
|
|
|
|
|
|
8,470 |
|
|
|
|
|
|
|
(8,470 |
) |
|
|
|
|
Cost of Gas and Liquids |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended March 31, 2007 |
|
|
146,941 |
|
|
|
64,996 |
|
|
|
|
|
|
|
|
|
|
|
211,937 |
|
For the three months ended March 31, 2006 |
|
|
139,224 |
|
|
|
57,512 |
|
|
|
|
|
|
|
|
|
|
|
196,736 |
|
Segment Margin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended March 31, 2007 |
|
|
30,178 |
|
|
|
14,313 |
|
|
|
|
|
|
|
|
|
|
|
44,491 |
|
For the three months ended March 31, 2006 |
|
|
24,642 |
|
|
|
9,888 |
|
|
|
|
|
|
|
|
|
|
|
34,530 |
|
Operation and Maintenance |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended March 31, 2007 |
|
|
9,115 |
|
|
|
1,810 |
|
|
|
|
|
|
|
|
|
|
|
10,925 |
|
For the three months ended March 31, 2006 |
|
|
8,298 |
|
|
|
1,147 |
|
|
|
|
|
|
|
|
|
|
|
9,445 |
|
Depreciation and Amortization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended March 31, 2007 |
|
|
7,885 |
|
|
|
3,250 |
|
|
|
292 |
|
|
|
|
|
|
|
11,427 |
|
For the three months ended March 31, 2006 |
|
|
6,010 |
|
|
|
2,987 |
|
|
|
172 |
|
|
|
|
|
|
|
9,169 |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2007 |
|
|
672,524 |
|
|
|
321,225 |
|
|
|
37,810 |
|
|
|
|
|
|
|
1,031,559 |
|
December 31, 2006 |
|
|
648,116 |
|
|
|
316,038 |
|
|
|
48,931 |
|
|
|
|
|
|
|
1,013,085 |
|
Investments in Unconsolidated Subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
|
5,616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,616 |
|
Expenditures for Long-Lived Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended March 31, 2007 |
|
|
35,547 |
|
|
|
4,385 |
|
|
|
87 |
|
|
|
|
|
|
|
40,019 |
|
For the three months ended March 31, 2006 |
|
|
14,727 |
|
|
|
15,530 |
|
|
|
121 |
|
|
|
|
|
|
|
30,378 |
|
The table below provides a reconciliation of total segment margin to net loss.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, 2007 |
|
|
March 31, 2006 |
|
|
|
(in thousands) |
|
Total Segment Margin (from above) |
|
$ |
44,491 |
|
|
$ |
34,530 |
|
Operation and maintenance |
|
|
(10,925 |
) |
|
|
(9,445 |
) |
General and administrative |
|
|
(6,851 |
) |
|
|
(5,416 |
) |
Loss on sale
of assets |
|
|
(1,808 |
) |
|
|
|
|
Management
services termination fee |
|
|
|
|
|
|
(9,000 |
) |
Depreciation and amortization |
|
|
(11,427 |
) |
|
|
(9,169 |
) |
|
|
|
|
|
|
|
Operating Income |
|
|
13,480 |
|
|
|
1,500 |
|
Interest expense, net |
|
|
(14,885 |
) |
|
|
(8,001 |
) |
Other income and deductions, net |
|
|
110 |
|
|
|
182 |
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(1,295 |
) |
|
$ |
(6,319 |
) |
|
|
|
|
|
|
|
9. Equity-Based Compensation
In December 2005, the compensation committee of the board of directors of the Partnerships
managing general partner approved a long-term incentive plan (LTIP) for the Partnerships
employees, directors and consultants covering an aggregate of 2,865,584 common units. Awards under
the LTIP have been made since completion of the Partnerships IPO. LTIP awards generally vest on
the basis of one-third of the award each year. The options expire ten years after the grant date.
The fair value of each option award is estimated on the date of grant using the Black-Scholes
Option Pricing Model. The following assumptions apply to the options granted for the periods
presented.
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, 2007 |
Weighted average expected life (years) |
|
|
4 |
|
Weighted average expected dividend per unit |
|
$ |
1.48 |
|
Weighted average grant date fair value of options |
|
$ |
1.34 |
|
Weighted average grant date fair value of restricted common units |
|
$ |
22.85 |
|
Weighted average risk free rate |
|
|
4.6 |
% |
Weighted average expected volatility |
|
|
16.0 |
% |
Weighted average expected forfeiture rate |
|
|
11.0 |
% |
The Partnership will make distributions to non-vested restricted common units at the same rate
as the common units. Restricted common units are subject to contractual restrictions against
transfer which lapse over time; non-vested restricted units are subject to forfeitures on
termination of employment. Upon the vesting and exercise of the common unit options, the
Partnership intends to settle these obligations with common units on a net basis. Accordingly, the
Partnership expects to recognize an aggregate of $11,702,000 of compensation expense related to the
grants under LTIP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
Weighted |
|
Aggregate |
|
|
|
|
|
|
Average |
|
Average |
|
Intrinsic |
|
|
|
|
|
|
Exercise |
|
Contractual |
|
Value * |
Common Unit Options |
|
Units |
|
Price |
|
Term (Years) |
|
(in thousands) |
Outstanding at beginning of period |
|
|
909,600 |
|
|
$ |
21.06 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
17,000 |
|
|
|
27.40 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(11,967 |
) |
|
|
20.00 |
|
|
|
|
|
|
|
|
|
Forfeited or expired |
|
|
(29,767 |
) |
|
|
21.77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period |
|
|
884,866 |
|
|
|
21.17 |
|
|
|
9.0 |
|
|
$ |
4,591 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period |
|
|
199,567 |
|
|
|
20.02 |
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
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 each period presented. Unit options with a strike price greater than
the closing market price are excluded. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average |
|
|
|
|
|
|
Grant Date |
Restricted
(Non-Vested) Units |
|
Units |
|
Fair Value |
Outstanding at beginning of period |
|
|
516,500 |
|
|
$ |
21.06 |
|
Granted |
|
|
191,000 |
|
|
|
27.70 |
|
Vested |
|
|
|
|
|
|
|
|
Forfeited or expired |
|
|
(20,000 |
) |
|
|
21.24 |
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period |
|
|
687,500 |
|
|
|
22.90 |
|
|
|
|
|
|
|
|
|
|
10. Subsequent Events
Partner Distributions. On April 26, 2007, the Partnership declared a distribution of $0.38
per common and subordinated unit, payable on May 15, 2007 to unitholders of record at the close of
business on May 8, 2007.
Acquisition of Pueblo Midstream Gas Corporation. On April 2, 2007, the Partnership and its
indirect wholly-owned subsidiary, Pueblo Holdings, Inc., a Delaware corporation (Pueblo
Holdings), entered into a definitive Stock Purchase Agreement (the Stock Purchase Agreement)
with Bear Cub Investments, LLC, a Colorado limited liability company, the members of that company
(the Members) and Robert J. Clark, as Sellers Representative, pursuant to which the Partnership
and Pueblo Holdings on that date acquired all the outstanding equity of Pueblo Midstream Gas
Corporation, a Texas corporation (Pueblo), from the Members (the Pueblo Acquisition). Pueblo
owns and operates natural gas gathering, treating and processing assets located in south Texas.
These assets are comprised of a 75 MMcf/d gas processing and treating facility (Fashing Processing
Plant), 33 miles of gathering pipelines and approximately 6,000 horsepower of compression.
The purchase price for the Pueblo Acquisition consisted of (1) the issuance of 751,597 common
units of the Partnership to the Members, valued at $19,722,000,
(2) the payment of $34,513,000 in cash and (3) the assumption
of $6,255,000 of liabilities. The cash portion of the consideration is subject to customary post-closing adjustments
and was financed out of the proceeds of the Partnerships revolving credit facility.
In connection with the Pueblo Acquisition, the Partnership entered into a Registration Rights
Agreement (the Registration Rights Agreement) with the Members. The Registration Rights
Agreement provides these persons with rights under the Securities Act of 1933 to register the
offering and sale of the common units of the Partnership that were issued to the Members pursuant
to the Stock Purchase Agreement.
Proposed sale of NGLs pipeline. In April 2007, the Partnership entered into a letter of
intent to sell a 34 mile east Texas NGLs pipeline for $3,000,000. The Partnership expects to close this sale
in the second quarter of 2007.
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
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 unaudited condensed consolidated financial statements and notes included
elsewhere in this document.
OVERVIEW
We are a Delaware limited partnership formed to capitalize on opportunities in the midstream
sector of the natural gas industry. We own and operate significant natural gas gathering and
processing assets in north Louisiana, east Texas, south Texas, west Texas and the mid-continent
region of the United States, which includes Kansas, Oklahoma, Colorado, and the Texas Panhandle.
We are engaged in gathering, processing, marketing and transporting natural gas and natural gas
liquids, or NGLs. We connect natural gas wells of producers to our gathering systems through which
we transport the natural gas to processing plants operated by us or by third parties. The
processing plants separate NGLs from the natural gas. We then sell and deliver the natural gas and
NGLs to a variety of markets.
In February 2006, we consummated the initial public offering of our common units. In August
2006, we acquired all the outstanding equity of TexStar Field Services, L.P. and its general
partner, TexStar GP, LLC (the TexStar acquisition), from HMTF Gas Partners II, L.P. (HMTF Gas
Partners), an affiliate of HM Capital Partners LLC (HM Capital Partners). Hicks Muse Equity
Fund V, L.P. (Fund V) and its affiliates, through HM Capital Partners, control our general
partner. Fund V controls HMTF Gas Partners through HM Capital Partners. Because our acquisition
of TexStar was a transaction between commonly controlled entities, we have accounted for the
transaction in a manner similar to a pooling of interests, and we have updated our historical
financial statements to include the financial condition and results of operations of TexStar for
periods during which common control existed (December 1, 2004 forward).
HOW WE EVALUATE OUR OPERATIONS
Our 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 and operating and maintenance expenses on a segment
basis and EBITDA on a company-wide basis.
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 (1) the level of workovers or
recompletions of existing connected wells and successful drilling activity in areas currently
dedicated to our pipelines, (2) our ability to compete for volumes from successful new wells in
other areas and (3) 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.
To increase throughput volumes on our intrastate pipeline we must contract with shippers,
including producers and marketers, for supplies of natural gas. We routinely monitor producer and
marketing activities in the areas served by our transportation system in search of new supply
opportunities.
Segment Margin. We calculate our Gathering and Processing segment margin as our revenue
generated from our gathering and processing operations minus the cost of natural gas and NGLs
purchased and other cost of sales, including third-party transportation and processing fees.
Revenue includes revenue from the sale of natural gas and NGLs resulting from these activities and
fixed fees associated with the gathering and processing of natural gas.
We calculate our Transportation segment margin as revenue generated by fee income as well as,
in those instances in which we purchase and sell gas for our account, gas sales revenue minus the
cost of natural gas that we purchase and transport. Revenue primarily includes fees for the
transportation of pipeline-quality natural gas and the margin generated by sales of natural gas
transported for our account. Most of our segment margin is fee-based with little or no commodity
price risk. We generally purchase pipeline-quality natural gas at a pipeline inlet price adjusted
to reflect our transportation fee and we sell that gas at the pipeline outlet. We regard the
difference between the purchase price and the sale price as the economic equivalent of our
transportation fee.
Total Segment Margin. Segment margin from Gathering and Processing, together with segment
margin from Transportation, comprise total segment margin. We use total segment margin as a measure
of performance. The following table reconciles the non-GAAP financial measure, total segment
margin, to its most directly comparable GAAP measure, net income (loss).
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, 2007 |
|
|
March 31, 2006 |
|
|
|
(in thousands) |
|
Net loss |
|
$ |
(1,295 |
) |
|
$ |
(6,319 |
) |
Add (deduct): |
|
|
|
|
|
|
|
|
Operation and maintenance |
|
|
10,925 |
|
|
|
9,445 |
|
General and administrative |
|
|
6,851 |
|
|
|
5,416 |
|
Loss on sale
of assets |
|
|
1,808 |
|
|
|
|
|
Management services termination fee |
|
|
|
|
|
|
9,000 |
|
Depreciation and amortization |
|
|
11,427 |
|
|
|
9,169 |
|
Interest expense, net |
|
|
14,885 |
|
|
|
8,001 |
|
Other income and deductions, net |
|
|
(110 |
) |
|
|
(182 |
) |
|
|
|
|
|
|
|
Total segment margin |
|
$ |
44,491 |
|
|
$ |
34,530 |
|
|
|
|
|
|
|
|
Operation and Maintenance. Operation and maintenance expenses are 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 expenses. 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 from total revenues in
calculating segment margin because we separately evaluate commodity volume and price changes in
segment margin.
EBITDA. We define EBITDA as net income plus interest expense, provision for income taxes and
depreciation and amortization expense. EBITDA is used as a supplemental measure by our management
and by external users of our financial statements such as investors, commercial 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 partners; |
|
|
§ |
|
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. |
EBITDA should not be considered as an alternative to 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 master limited partnership. The
following table reconciles the non-GAAP financial measure, EBITDA, to its most directly comparable
GAAP measure, net loss and net cash flows provided by operating activities.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, 2007 |
|
|
March 31, 2006 |
|
|
|
(in thousands) |
|
Net cash flows provided by (used in) operating activities |
|
$ |
27,470 |
|
|
$ |
(471 |
) |
Add (deduct): |
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
(11,986 |
) |
|
|
(9,318 |
) |
Equity income |
|
|
43 |
|
|
|
91 |
|
Risk management portfolio value changes |
|
|
124 |
|
|
|
191 |
|
Loss on sale of assets |
|
|
(1,808 |
) |
|
|
|
|
Unit based compensation expenses |
|
|
(1,103 |
) |
|
|
(314 |
) |
Changes in current assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
1,959 |
|
|
|
(16,938 |
) |
Other current assets |
|
|
(598 |
) |
|
|
(921 |
) |
Accounts payable and accrued liabilities |
|
|
(5,220 |
) |
|
|
23,535 |
|
Accrued taxes payable |
|
|
(203 |
) |
|
|
(273 |
) |
Interest payable |
|
|
(11,918 |
) |
|
|
|
|
Other current liabilities |
|
|
1,504 |
|
|
|
(12 |
) |
Other assets |
|
|
441 |
|
|
|
(2,515 |
) |
Other liabilities |
|
|
|
|
|
|
626 |
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(1,295 |
) |
|
$ |
(6,319 |
) |
Add: |
|
|
|
|
|
|
|
|
Interest expense, net |
|
|
14,885 |
|
|
|
8,001 |
|
Depreciation and amortization |
|
|
11,427 |
|
|
|
9,169 |
|
|
|
|
|
|
|
|
EBITDA |
|
$ |
25,017 |
|
|
$ |
10,851 |
|
|
|
|
|
|
|
|
CASH DISTRIBUTIONS
On April 26, 2007, the Partnership declared a distribution of $0.38 per common and
subordinated unit, payable on May 15, 2007 to unitholders of record at the close of business on May
8, 2007.
RESULTS OF OPERATIONS
Three Months Ended March 31, 2007 vs. Three Months Ended March 31, 2006
The following table contains key company-wide performance indicators related to our discussion
of the results of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
|
|
|
March 31, 2007 |
|
|
March 31, 2006 |
|
|
Change |
|
|
Percent |
|
|
|
(in thousands except percentages and volume data) |
|
|
|
|
|
Revenues |
|
$ |
256,428 |
|
|
$ |
231,266 |
|
|
$ |
25,162 |
|
|
|
11 |
% |
Cost of gas and liquids |
|
|
211,937 |
|
|
|
196,736 |
|
|
|
15,201 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment margin (1) |
|
|
44,491 |
|
|
|
34,530 |
|
|
|
9,961 |
|
|
|
29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance |
|
|
10,925 |
|
|
|
9,445 |
|
|
|
1,480 |
|
|
|
16 |
|
General and administrative |
|
|
6,851 |
|
|
|
5,416 |
|
|
|
1,435 |
|
|
|
26 |
|
Loss on sale
of assets
|
|
|
1,808 |
|
|
|
|
|
|
|
1,808 |
|
|
|
N/M |
|
Management services termination fee
|
|
|
|
|
|
|
9,000 |
|
|
|
(9,000 |
) |
|
|
N/M |
|
Depreciation and amortization |
|
|
11,427 |
|
|
|
9,169 |
|
|
|
2,258 |
|
|
|
25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
13,480 |
|
|
|
1,500 |
|
|
|
11,980 |
|
|
|
799 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net |
|
|
(14,885 |
) |
|
|
(8,001 |
) |
|
|
6,884 |
|
|
|
86 |
|
Other income and deductions, net |
|
|
110 |
|
|
|
182 |
|
|
|
(72 |
) |
|
|
(40 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(1,295 |
) |
|
$ |
(6,319 |
) |
|
$ |
(5,024 |
) |
|
|
80 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
System inlet volumes (MMbtu/d) (2) |
|
|
1,133,844 |
|
|
|
861,989 |
|
|
|
271,855 |
|
|
|
32 |
|
|
|
|
(1) |
|
For reconciliation of total segment margin to its most directly comparable financial
measure calculated and presented in accordance with GAAP, please read Item 2. Managements
Discussion and Analysis of Financial Condition and Results of Operations How We Evaluate Our
Operations. |
|
(2) |
|
System inlet volumes include total volumes taken into both our gathering and processing system
and our transportation systems. |
|
N/M |
|
Not meaningful |
The table below contains key segment performance indicators related to our discussion of the
results of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
March 31, 2007 |
|
March 31, 2006 |
|
Change |
|
Percent |
|
|
(in thousands except
percentages and volume data) |
Segment Financial and Operating Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and Processing Segment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment margin |
|
$ |
30,178 |
|
|
$ |
24,643 |
|
|
$ |
5,535 |
|
|
|
22 |
% |
Operation and maintenance |
|
|
9,115 |
|
|
|
8,298 |
|
|
|
817 |
|
|
|
10 |
|
Operating data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput (MMbtu/d) |
|
|
729,218 |
|
|
|
423,593 |
|
|
|
305,625 |
|
|
|
72 |
|
NGL gross production (Bbls/d) |
|
|
20,047 |
|
|
|
17,478 |
|
|
|
2,569 |
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation Segment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment margin |
|
$ |
14,313 |
|
|
$ |
9,887 |
|
|
$ |
4,426 |
|
|
|
45 |
|
Operation and maintenance |
|
|
1,810 |
|
|
|
1,147 |
|
|
|
663 |
|
|
|
58 |
|
Operating data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput (MMbtu/d) |
|
|
704,458 |
|
|
|
438,396 |
|
|
|
266,062 |
|
|
|
61 |
|
Net Loss. Net loss for the three months ended March 31, 2007 decreased $5,024,000
compared with the three months ended March 31, 2006. The primary reasons for this decrease are an
increase in total segment margin of $9,961,000, or 29 percent, primarily due to increased
throughput volumes in the transportation segment, operations of two north Louisiana refrigeration
plants in the gathering and processing segment in 2007 and the absence in 2007 of management
services termination fees of $9,000,000 paid in 2006 in connection with our IPO. Partially
offsetting the decrease in net loss were the following items:
|
§ |
|
An increase in interest expense, net of $6,884,000 primarily due to increased levels
of borrowings used primarily to finance our growth capital projects; |
|
|
§ |
|
an increase in depreciation and amortization of $2,258,000 primarily due to higher
levels of depreciation from projects completed since March 31, 2006; |
|
|
§ |
|
a loss on the sale of certain non-core assets of $1,808,000 in the three months ended
March 31, 2007; |
|
|
§ |
|
an increase in operation and maintenance expense of $1,480,000 primarily due to an
unplanned outage in the transportation segment and organic growth in the gathering and
processing segment; and |
|
|
§ |
|
an increase in general and administrative expense of $1,435,000 primarily due to
higher employee related expenses and increased expenses associated with our long-term
incentive plan. |
Segment Margin. Segment margin for the three months ended March 31, 2007 increased $9,961,000
compared with the three months ended March 31, 2006. This increase was attributable to an increase
of $5,535,000 in gathering and processing segment margin and an increase of $4,426,000 in
transportation segment margin, discussed below.
Gathering and processing segment margin increased to $30,178,000 for the three months ended
March 31, 2007 from $24,643,000 for the three months ended March 31, 2006, an increase of
$5,535,000, or 22 percent. The major components of this increase were as follows:
|
§ |
|
$2,610,000 attributable to the operations of the Elm Grove and Dubberly refrigeration
plants in North Louisiana, which began operations in May 2006 and December 2006,
respectively; |
|
|
§ |
|
$1,531,000 attributable to the operation of the LaSalle County Phase II organic
growth project in South Texas, which began operations in December 2006; and |
|
|
§ |
|
$1,394,000 primarily attributable to increased throughput volumes in north Louisiana
and south Texas, partially offset by lower unit margins in west Texas. |
Transportation segment margin increased to $14,313,000 for the three months ended March 31,
2007 from $9,887,000 for the three months ended March 31, 2006, an increase of $4,426,000, or 45
percent. The major components of this increase were as follows:
|
§ |
|
$4,765,000 attributable to an increase in throughput volumes; |
|
|
§ |
|
$778,000 attributable to increased average gross margin per MMBtu of throughput; and partially offset by |
|
|
§ |
|
lower margins of $1,117,000 from marketing activity generated by our merchant function. |
Eastside Compressor Fire. On March 18, 2007, a fire occurred at the Eastside Compressor
Station on our Regency Intrastate Pipeline system. Of the three compressor units in the station,
one was damaged beyond repair, the second unit sustained reparable damage and the third was
slightly damaged. The third unit was restored to service in less than 40 hours. We have installed
two smaller surplus compressors and three rental compressors to the site which provides temporary
compression horsepower to offset the loss of the second units capacity. The second unit is
expected to be back in service by the end of May 2007 at which time we expect to return to normal
operations. There were no personal injuries as a result of the incident. The replacement unit for
the severely damaged compressor is not expected to be in service until late third or early fourth
quarter of 2007. We are managing the system with existing compressors on other parts of the system
and with careful gas management. The Louisiana Department of Environmental Quality has granted a
request for an emissions variance for the temporary compressors. While preliminary estimates of
property damage are in the range of $5,500,000 to $6,900,000, the equipment is fully insured,
subject to a deductible of $250,000. To date, this incident has had no material adverse effect on
our business. Through the expedited installation of temporary compression and the careful
management of the system we have been able to mitigate and anticipate that we will be able to
continue to mitigate any material disruption to our business. To date, we have not experienced any
material adverse effect on our ability to maintain pre-incident levels of gas flow. If we are
unable to do so, however, we maintain insurance that we believe will protect us against any
materially adverse financial effect. Our business interruption insurance is subject to a
deductible for losses and expenses incurred during the first 30 days following an incident which
will include our costs of mobilizing and installing the temporary
compressors and the cost of gas losses at the time of the incident, estimated at
$850,000. The total estimated deductible is $1,100,000.
Operation and Maintenance. Operations and maintenance expense increased to $10,925,000 in the
three months ended March 31, 2007 from $9,445,000 for the corresponding period in 2006, a 16
percent increase. This increase is the result of the following factors:
|
§ |
|
$463,000 of unplanned outage expense in the transportation segment in 2007 related to
the eastside compressor fire discussed above; |
|
|
§ |
|
$424,000 of increased employee related expenses primarily in the gathering and
processing segment resulting from additional employees related to system expansion and
employee annual pay raises; |
|
|
§ |
|
$274,000 of increased consumable expenses primarily in the gathering and processing
segment resulting from two of our north Louisiana refrigeration plants and additional
compressor units put into service subsequent to March 31, 2006; |
|
|
§ |
|
$237,000 of increased utility expense primarily in the gathering and processing
segment resulting from two of our north Louisiana refrigeration plants put into service
subsequent to March 31, 2006; |
|
|
§ |
|
$184,000 of increased non-income taxes resulting from a higher property taxes
associated with our transportation system in north Louisiana; and |
|
|
§ |
|
$102,000 decrease in contractor expenses primarily in the gathering and processing
segment resulting from the hiring of additional personnel discussed above. |
General and Administrative. General and administrative expense increased to $6,851,000 in the
three months ended March 31, 2007 from $5,416,000 for the same period in 2006, a 26 percent
increase. The increase is primarily due to the following factors:
|
§ |
|
$789,000 of increased expenses associated with our long-term incentive plan that
primarily relate to the issuance of restricted units in the three months ended March 31,
2007 and |
|
|
§ |
|
$624,000 of increased employee related expenses resulting from hiring senior level personnel to assist us in achieving our strategic objectives. |
Other. In the three months ended March 31, 2006, we recorded a one-time charge of $9,000,000
for the termination of two long-term management services contracts in connection with our IPO. In
the three months ended March 31, 2007, we sold selected non-core pipelines, related rights of way
and contracts located in south Texas for $5,340,000 in cash on March 31, 2007 and recorded a
related charge of $1,808,000.
Depreciation and Amortization. Depreciation and amortization expense increased to $11,427,000
in the three months ended March 31, 2007 from $9,169,000 for the three months ended March 31, 2006,
a 25 percent increase. The increase is due to higher depreciation expense of $1,724,000 from
projects completed since March 31, 2006 and higher identifiable intangible asset amortization of
$534,000 related to contracts acquired in July 2006.
Interest Expense, Net. Interest expense, net increased $6,884,000, or 86 percent, in the
three months ended March 31, 2007 compared to the same period in 2006. Of this increase,
$5,285,000 was attributable to increased levels of borrowings and $1,789,000 was attributable to
higher interest rates partially offset by $190,000 of amortization from interest rate swap
termination proceeds from other comprehensive income. The unamortized balance of interest rate
swap termination proceeds in other comprehensive income at March 31, 2007 was $888,000.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Conformity with GAAP requires management to make estimates and assumptions that affect the
amounts reported in the financial statements and notes. Although these estimates are based on
managements best available knowledge of current and expected future events, actual results could
be different from those estimates. We believe that the following are the more critical judgment
areas in the application of our accounting policies that currently affect our financial condition
and results of operations.
Revenue and Cost of Sales Recognition. We record revenue and cost of gas and liquids for
those transactions where we act as the principal and take title to gas that we purchase for resale.
When our customers pay us a fee for providing a service such as gathering or transportation we
record the fees separately in revenues. In March 2006, we implemented a process for estimating
certain revenue and expenses as actual amounts are not confirmed until after the financial closing
process due to the standard settlement dates in the gas industry. We calculate estimated revenues
using actual pricing and nominated volumes. In the subsequent production month, we reverse the
accrual and record the actual results. Prior to the settlement date, we record actual operating
data to the extent available, such as actual operating and maintenance and other expenses. We do
not expect actual results to differ materially from our estimates.
Risk Management Activities. In order to protect ourselves from commodity and interest rate
risk, we pursue hedging activities to minimize those risks. These hedging activities rely upon
forecasts of our expected operations and financial structure over the next three years. If our
operations or financial structure are significantly different from these forecasts, we could be
subject to adverse financial results as a result of these hedging activities. We mitigate this
potential exposure by retaining an operational cushion between our forecasted transactions and the
level of hedging activity executed. We monitor and review hedging positions regularly. We elected
hedge accounting under SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended, for all of our swap contracts but not for our crude oil put options.
Accordingly, we record the unrealized changes in fair value in other comprehensive income (loss) to
the extent the hedges are effective.
Purchase Method of Accounting. We make various assumptions in determining the fair values of
acquired assets and liabilities. In order to allocate the purchase price to the business units, we
develop fair value models with the assistance of outside consultants. These fair value models
apply discounted cash flow approaches to expected future operating results, considering expected
growth rates, development opportunities, and future pricing assumptions. An economic value is
determined for each business unit. We then determine the fair value of the fixed assets based on
estimates of replacement costs. Intangible assets acquired consist primarily of licenses, permits
and customer contracts. We make assumptions regarding the period of time it would take to replace
these licenses and permits. We assign value using a lost profits model over that period of time
necessary to replace the licenses and permits. We value the customer contracts using a discounted
cash flow model. We determine liabilities assumed based on their expected future cash outflows.
We record goodwill as the excess of the cost of each business unit over the sum of amounts assigned
to the tangible assets and separately recognized intangible assets acquired less liabilities
assumed of the business unit.
Depreciation Expense and Cost Capitalization. Our assets consist primarily of natural gas
gathering pipelines, processing plants, and transmission pipelines. We capitalize all
construction-related direct labor and material costs, as
well as indirect construction costs.
Indirect construction costs include general engineering and the costs of funds used in
construction. Capitalized interest represents the cost of funds used to finance the construction
of new facilities and is expensed over the life of the constructed asset through the recording of
depreciation expense. We capitalize the costs of renewals and betterments that extend the useful
life, while we expense the costs of repairs, replacements and maintenance projects as incurred.
We generally compute depreciation using the straight-line method over the estimated useful
life of the assets. Certain assets such as land, NGL line pack and natural gas line pack are
non-depreciable. The computation of depreciation expense requires judgment regarding the estimated
useful lives and salvage value of assets. As circumstances warrant, we review depreciation
estimates to determine if any changes are needed. Such changes could involve an increase or
decrease in estimated useful lives or salvage values, which would affect future depreciation
expense.
Equity Based Compensation. The fair value of each option award is estimated on the date of
grant using the Black-Scholes Option Pricing Model. For information as to the assumptions
applicable to options granted during the quarter ended March 31, 2007, see note 9 of Notes to
Unaudited Condensed Consolidated Financial Statements.
OTHER MATTERS
Legal. Blackbrush Oil & Gas LLC, owned by an affiliate of HM Capital that was the seller in our
acquisition of TexStar Field Services, L.P., and certain of its subsidiaries are defendants in a
wrongful death action styled Takas v. Strait Energy Services LLC et al. brought in state district
court in Jim Wells County, Texas. The claim for both actual and punitive damages is made on behalf
of the wife of the driver of a tractor trailer truck who was killed when the truck was struck by a
train at a railway crossing. The truck was owned by a subcontractor working on, and was enroute
to, a construction site relating to a pipeline owned by an entity that was then a subsidiary of
TexStar. This accident occurred on July 15, 2005, prior to our acquisition of TexStar on August
15, 2006. We have been advised by representatives of Blackbrush that the entity that owned the
pipeline, which is now our subsidiary (Regency Frio NewLine LP), is likely to be named as a
defendant in the litigation as a result of Blackbrushs reply to the complaint. We have notified
our insurance carrier regarding this matter, and we do not expect it to have a material adverse
effect on our financial condition or our results of operations.
The
Partnership is involved in various other claims and lawsuits incidental to its business.
In the opinion of management, these claims and lawsuits in the aggregate will not have a material
adverse effect on our business, financial condition, results of operations or cash flows.
Escrow Payable. At March 31, 2007, $5,848,000 remained in escrow pending the completion by El
Paso Field Services, LP (El Paso) of environmental remediation projects pursuant to the purchase
and sale agreement (El Paso PSA) related to the assets in north Louisiana and in the
mid-continent area. In the El Paso PSA, El Paso indemnified the Regency LLC Predecessor against
losses arising from pre-closing and known environmental liabilities subject to a limit of
$84,000,000 and subject to certain deductible limits. Upon completion of a Phase II environmental
study, Regency LLC Predecessor notified El Paso of remediation obligations amounting to $1,800,000
with respect to known environmental matters and $3,600,000 with respect to pre-closing
environmental liabilities. Upon satisfactory completion of the remediation by El Paso, the amount
held in escrow will be released. These contractual rights of Regency LLC Predecessor were
continued by the Partnership.
Environmental. Waha Phase I. A Phase I environmental study was performed on the Waha assets
in connection with the pre-acquisition due diligence process in 2004. Most of the identified
environmental contamination had either been remediated or was being remediated by the previous
owners or operators of the properties. The estimated potential environmental remediation costs at
specific locations were $1,900,000 to $3,100,000. No governmental agency has required that the
Partnership undertakes these remediation efforts. Management believes that the likelihood that it
will be liable for any significant potential remediation liabilities identified in the study is
remote. Separately, the Partnership acquired an environmental pollution liability insurance policy
in connection with the acquisition to cover any undetected or unknown pollution discovered in the
future. The policy covers clean-up costs and damages to third parties, and has a 10-year term
(expiring 2014) with a $10,000,000 limit subject to certain deductibles.
Regulatory Environment. In August 2005, Congress enacted and the President signed the Energy
Policy Act of 2005. With respect to the oil and gas industry, the new legislation focuses on the
exploration and production sector, interstate pipelines, and refinery facilities. In many cases,
the Act requires action by various government agencies over the near to mid-term. Management is
unable to determine what impact, if any, the Act will have on its operations and cash flows.
LIQUIDITY AND CAPITAL RESOURCES
We expect our sources of liquidity to include:
|
§ |
|
cash generated from operations; |
|
|
§ |
|
borrowings under our credit facility; |
|
|
§ |
|
debt offerings; and |
|
|
§ |
|
issuance of additional partnership units. |
We believe that the cash generated from these sources will be sufficient to meet our minimum
quarterly cash distributions and our requirements for short-term working capital and growth capital
expenditures for the next twelve months.
Working Capital Surplus (Deficit). Working capital is the amount by which current assets
exceed current liabilities and is a measure of our ability to pay our liabilities as they become
due. During periods of growth capital expenditures, we experience working capital deficits when we
fund construction expenditures out of working capital until they are permanently financed. Our
working capital is also influenced by current risk management assets and liabilities due to fair
market value changes in our derivative positions being reflected on our balance sheet. These
represent our expectations for the settlement of risk management rights and obligations over the
next twelve months, and so must be viewed differently from trade accounts receivable and accounts
payable which settle over a much shorter span of time. When our derivative positions are settled,
we expect an offsetting physical transaction, and, as a result, we do not expect risk management
assets and liabilities to affect our ability to pay bills as they come due.
Our working capital deficit increased by $9,767,000 from December 31, 2006 to March 31, 2007
primarily due to the following:
|
§ |
|
An increase in interest payable of $11,918,000 due to interest accruals on our
senior notes borrowings with payments due each June 15th and December
15th as compared to monthly interest payments on borrowings under our credit
facility; |
|
|
§ |
|
a net increase of $7,968,000 in liabilities from risk management activities
primarily due to an increase in the commodity prices we expect to pay (index prices) on
our outstanding swaps as compared to the commodity prices we will receive upon
settlement of our swaps; offset by |
|
|
§ |
|
a net decrease in net accounts receivable and accounts payable of $10,518,000 due
the timing of receipts and payments. |
Cash Flows from Operations. Net cash flows provided by operating activities increased
$27,941,000 for the three months ended March 31, 2007 as compared to the three months ended March
31, 2006. Net loss decreased $5,024,000 from 2006 to 2007 primarily due to increased operating
income of $11,980,000 offset by an increase in interest expense of $6,884,000 due to higher average
outstanding debt balances. For the reason indicated above, cash flows for interest payable
increased $11,918,000 due to interest accruals on our senior notes. Cash flows from accounts
receivable and accounts payable and accrued liabilities decreased
$9,858,000 due to the timing of
receipts and payments.
Cash Flows from Investing Activities. Net cash flows used in investing activities increased
$16,513,000, or 54 percent, in the three months ended March 31, 2007 compared to the three months
ended March 31, 2006. The increase is primarily due to higher growth and maintenance capital
expenditures discussed in Capital Requirements.
Cash Flows from Financing Activities. Net cash flows provided by financing activities
decreased $12,165,000, or 39 percent, in the three months ended March 31, 2007 compared to the
three months ended March 31, 2006 primarily due to (1) an increase in borrowings under our credit
facility of $11,275,000 used primarily for growth capital projects; (2) a decrease of $8,977,000
related to IPO proceeds received in 2006 not received in 2007; and (3) an increase in partner
distributions of $14,620,000 as there were no partner distributions paid in the quarter ended March
31, 2006.
Capital Requirements
We categorize our capital expenditures as either:
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Growth capital expenditures, which are made to acquire additional assets to increase
our business, to expand and upgrade existing systems and facilities or to construct or
acquire similar systems or facilities; or |
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Maintenance capital expenditures, which are made to replace partially or fully
depreciated assets, to maintain the existing operating capacity of our assets and to
extend their useful lives or to maintain existing system volumes and related cash flows. |
Growth Capital Expenditures. In the three months ended March 31, 2007, we incurred
$37,348,000 of growth capital expenditures. Growth capital expenditures primarily relate to growth
capital projects listed below and our acquisition of the outstanding interest in the Palafox Joint
Venture that we did not own (50 percent) for $5,000,000 in February 2007.
Our 2007 growth budget includes approximately $55,000,000 of currently identified organic
growth capital expenditures. These growth capital expenditures are for more than 25 projects, of
which the most significant are the following:
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Re-build and activate an existing nitrogen rejection unit at our
Eustace Processing Plant; |
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Constructing 20 miles of 10 inch diameter pipeline, which will connect
the Fashing Processing Plant to our Tilden Processing Plant in south Texas; |
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Constructing 31 miles of 12 inch diameter pipeline in south Texas; and |
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Electrification and adding an acid gas injection well at our Tilden Processing Plant. |
Maintenance Capital Expenditures. In the three months ended March 31, 2007, we incurred
$864,000 of maintenance capital expenditures. Maintenance capital expenditures primarily consist
of compressor and equipment overhauls, as well as new well connects to our gathering systems, which
replace volumes from naturally occurring depletion of wells already connected.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are a net seller of NGLs, and as such our financial results are exposed to fluctuations in
NGLs pricing. We have executed swap contracts settled against crude oil, ethane, propane, butane
and natural gasoline market prices, supplemented with crude oil put options. We have hedged our
expected exposure to declines in prices for NGLs, condensate and natural gas volumes produced for
our account in the approximate percentages set forth below:
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2007 |
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2008 |
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2009 |
NGL |
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73 |
% |
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71 |
% |
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28 |
% |
Condensate |
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67 |
% |
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65 |
% |
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65 |
% |
Natural Gas |
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58 |
% |
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0 |
% |
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0 |
% |
We continually monitor our hedging and contract portfolio and expect to continue to
adjust our hedge position as conditions warrant.
The following table sets forth certain information regarding our NGL swaps outstanding at
March 31, 2007. The relevant index price that we pay is the monthly average of the daily closing
price for deliveries of commodities into Mont Belvieu, Texas as reported by the Oil Price
Information Service (OPIS).
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We |
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Fair Value |
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Period |
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Commodity |
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Notional Volume |
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Pay |
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We Receive |
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(in thousands) |
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April 2007 December 2008 |
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Ethane |
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1,246 (MBbls) |
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Index |
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$0.55-$0.655 ($/gallon) |
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$ |
(2,590 |
) |
April 2007 December 2009 |
|
Propane |
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1,112 (MBbls) |
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Index |
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$0.825-$1.10 ($/gallon) |
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(4,106 |
) |
April 2007 December 2009 |
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Butane |
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714 (MBbls) |
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Index |
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$1.025-$1.273 ($/gallon) |
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(2,731 |
) |
April 2007 December 2009 |
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Natural Gasoline |
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337 (MBbls) |
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Index |
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$1.22- $1.59 ($/gallon) |
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(1,399 |
) |
April 2007 December 2009 |
|
West Texas Intermediate Crude |
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654 (MBbls) |
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Index |
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$65.60-$68.38 ($/Bbl) |
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(1,048 |
) |
April 2007 December 2007 |
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NYMEX Natural Gas |
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5,000 (MMBtu/d) |
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Index |
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$7.91 ($/MMBtu) |
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(493 |
) |
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Total Fair Value
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$ |
(12,367 |
) |
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Item 4. Controls and Procedures
Disclosure controls. At the end of the period covered by this report, an evaluation was
performed under the supervision and with the participation of our management, including the Chief
Executive Officer and Chief Financial Officer of our managing general partner, of the effectiveness
of the design and operation of our disclosure controls and procedures (as such terms are defined in
Rule 13a15(e) and 15d15(e) of the Exchange Act). Based on that evaluation, management, including
the Chief Executive Officer and Chief Financial Officer of our managing general partner, concluded
that our disclosure controls and procedures were effective as of March 31, 2007 to provide
reasonable assurance that information required to be disclosed by us in the reports that we file or
submit under the Exchange Act is properly recorded, processed, summarized and reported, within the
time periods specified in the SECs rules and forms.
Internal control over financial reporting. In anticipation of becoming subject to the
provisions of Section 404 of the Sarbanes-Oxley Act of 2002, we initiated in early 2005 a program
of documentation, implementation and testing of internal control over financial reporting. This
program will continue through this year, culminating with our initial Section 404 certification and
attestation in early 2008.
To the extent that we discover any matter in the design or operation of our system of internal
control over financial reporting that might be considered to be a significant deficiency or a
material weakness, whether or not considered reasonably likely to affect adversely our ability to
record, process, summarize and report financial information properly, we report that matter to our
independent registered public accounting firm and to the audit committee of our board of directors.
There have been no other changes in the Partnerships internal controls over financial
reporting that has materially affected, or is reasonably likely to affect, the Partnerships
internal controls over financial reporting.
PART II OTHER INFORMATION
Item 1. Legal Proceedings
The information required for this item is provided in Note 6, Commitments and Contingencies,
included in the notes to the unaudited condensed consolidated financial statements included under
Part I, Item 1, which information is incorporated by reference into this item.
Item 1A. Risk Factors
In addition to the other information set forth in this report, you should carefully consider
the factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the
year ended December 31, 2006, which could materially affect our business, financial condition or
future results. The risks described in our Annual Report on Form 10-K are not the only risks
facing our Partnership.
We have adopted certain valuation methodologies that may result in a shift of income, gain,
loss and deduction between the general partner and the unitholders. The IRS may challenge this
treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we determine the fair
market value of our assets and allocate any unrealized gain or loss attributable to our assets to
the capital accounts of our unitholders and our general partner. Our methodology may be viewed as
understating the value of our assets. In that case, there may be a shift of income, gain, loss and
deduction between certain unitholders and the general partner, which may be unfavorable to such
unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units
may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to
our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge
our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our
tangible and intangible assets, and allocations of income, gain, loss and deduction between the
general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount
of taxable income or loss being allocated to our unitholders. It also could affect the amount of
gain from our unitholders sale of common units and could have a negative impact on the value of
the common units or result in audit adjustments to our unitholders tax returns without the benefit
of additional deductions.
Additional risks and uncertainties not currently known to us or that we currently deem to be
immaterial also may materially adversely affect our business, financial condition and/or operating
results.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The information required for this item is provided in Note 10, Subsequent Events, included in
the notes to the unaudited condensed consolidated financial statements included under Part I, Item
1, which information is incorporated by reference into this item.
Item 6. Exhibits
The exhibits below are filed as a part of this report:
Exhibit 12.1 Computation of Ratio of Earnings to Fixed
Charges
Exhibit 31.1 Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
Exhibit 31.2 Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
Exhibit 32.1 Section 1350 Certifications of Chief Executive Officer
Exhibit 32.2 Section 1350 Certifications of Chief Financial Officer
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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REGENCY ENERGY PARTNERS LP |
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By: Regency GP LP, its general partner |
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By: Regency GP LLC, its general partner |
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/s/ Lawrence B. Connors |
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Lawrence B. Connors |
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Vice President of Accounting and Finance (Duly |
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Authorized Officer and Chief Accounting Officer) |
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May 14, 2007