form10q.htm
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
(Mark
One)
þ
|
|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934
|
|
|
For
the quarterly period ended September 30,
2008
|
OR
o
|
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934
|
|
|
For
the transition period from
____________ to
____________
|
Commission
File Number: 000-51757
REGENCY
ENERGY PARTNERS LP
(Exact
name of registrant as specified in its charter)
DELAWARE
|
16-1731691
|
(State
or other jurisdiction of incorporation or organization)
|
(I.R.S.
Employer Identification No.)
|
|
|
2001
BRYAN STREET, SUITE 3700
|
|
DALLAS,
TX
|
75201
|
(Address
of principal executive offices)
|
(Zip
Code)
|
|
|
(214)
750-1771
|
(Registrant’s
telephone number, including area code)
|
|
NONE
|
(Former
name, former address and former fiscal year, if changed since last
report.)
|
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.þ Yes o No
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definition of “large accelerated filer, accelerated
filer, and small reporting company” in Rule 12b-2 of the Exchange Act. (Check
one):
þ Large
accelerated
filer o Accelerated
filer
o Non-accelerated
filer (Do not check if a smaller reporting company) o Smaller
reporting company
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 54,815,951 common units, 7,276,506 Class D common units,
and 19,103,896 subordinated units outstanding as of October
31, 2008.
Introductory
Statement
References
in this report to the “Partnership,” “we,” “our,” “us” and similar terms, when
used in a historical context, refer to Regency Energy Partners LP, or the
Partnership, and to Regency Gas Services LLC, all the outstanding member
interests of which were contributed to the Partnership on February 3, 2006, and
its subsidiaries. When used in the present tense or prospectively,
these terms refer to the Partnership and its subsidiaries. We use the
following definitions in this quarterly report on Form 10-Q:
Name
|
Definition
or Description
|
ASC
|
ASC
Hugoton LLC, an affiliate of GECC
|
Bbls/d
|
Barrels
per day
|
Bcf
|
One
billion cubic feet
|
Bcf/d
|
One
billion cubic feet per day
|
BTU
|
A
unit of energy needed to raise the temperature of one pound of water by
one degree Fahrenheit
|
CDM
|
CDM
Resource Management LLC
|
CERCLA
|
Comprehensive
Environmental Response, Compensation and Liability Act
|
DOT
|
U.S.
Department of Transportation
|
EIA
|
Energy
Information Administration
|
EnergyOne
|
FrontStreet
EnergyOne LLC
|
El
Paso
|
El
Paso Field Services, LP
|
EPA
|
Environmental
Protection Agency
|
FASB
|
Financial
Accounting Standards Board
|
FERC
|
Federal
Energy Regulatory Commission
|
FrontStreet
|
FrontStreet
Hugoton LLC
|
GAAP
|
Accounting
principles generally accepted in the United States
|
GE
|
General
Electric Company
|
GE
EFS
|
General
Electric Energy Financial Services, a unit of GECC, combined with Regency
GP Acquirer LP and Regency LP Acquirer LP
|
GECC
|
General
Electric Capital Corporation, an indirect wholly owned subsidiary of
GE
|
General
Partner
|
Regency
GP LP, the general partner of the Partnership, or Regency GP LLC, the
general partner of Regency GP LP, which effectively manages the business
and affairs of the Partnership
|
GSTC
|
Gulf
States Transmission Corporation
|
HLPSA
|
Hazardous
Liquid Pipeline Safety Act
|
IRS
|
Internal
Revenue Service
|
LIBOR
|
London
Interbank Offered Rate
|
MMbtu
|
One
million BTUs
|
MMbtu/d
|
One
million BTUs per day
|
MMcf
|
One
million cubic feet
|
MMcf/d
|
One
million cubic feet per day
|
MQD
|
Minimum
Quarterly Distribution
|
Nexus
|
Nexus
Gas Holdings, LLC
|
NOE
|
Notice
of Enforcement
|
NGA
|
Natural
Gas Act of 1938
|
NGLs
|
Natural
gas liquids
|
NGPA
|
Natural
Gas Policy Act of 1978
|
NGPSA
|
Natural
Gas Pipeline Safety Act of 1968, as amended
|
NPDES
|
National
Pollutant Discharge Elimination System
|
Nasdaq
|
Nasdaq
Stock Market, LLC
|
NYMEX
|
New
York Mercantile Exchange
|
OSHA
|
Occupational
Safety and Health Act
|
Partnership
|
Regency
Energy Partners LP
|
Partnership
Agreement
|
Amended
and Restated Agreement of Limited Partnership of Regency Energy Partners
LP
|
Pueblo
|
Pueblo
Midstream Gas Corporation
|
RCRA
|
Resource
Conservation and Recovery Act
|
RGS
|
Regency
Gas Services LLC
|
RIGS
|
Regency
Intrastate Gas LLC
|
SEC
|
Securities
and Exchange Commission
|
SFAS
|
Statement
of Financial Accounting Standard
|
Sonat
|
Southern
Natural Gas Company
|
TCEQ
|
Texas
Commission on Environmental Quality
|
Tcf
|
One
trillion cubic feet
|
Tcf/d
|
One
trillion cubic feet per day
|
TRRC
|
Texas
Railroad Commission
|
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:
·
|
changes
in laws and regulations impacting the midstream and compression sectors of
the natural gas industry;
|
·
|
declines
in the credit markets and the availability of credit for us as well as for
producers connected to our systems and our customers;
|
·
|
the
level of creditworthiness of our counterparties and
customers;
|
·
|
our
ability to access the debt and equity markets;
|
·
|
our
use of derivative financial instruments to hedge commodity and interest
rate risks;
|
·
|
the
amount of collateral required to be posted from time to time in our
transactions;
|
·
|
changes
in commodity prices, interest rates, demand for our
services;
|
·
|
weather
and other natural phenomena;
|
·
|
industry
changes including the impact of consolidations and changes in
competition;
|
·
|
our
ability to obtain required approvals for construction or modernization of
our facilities and the timing of operations of such facilities;
and
|
·
|
the
effect of accounting pronouncements issued periodically by accounting
standard setting boards.
|
If one or
more of these risks or uncertainties materialize, or if underlying assumptions
prove incorrect, our actual results may differ materially from those
anticipated, estimated, projected or expected. Many of the factors
that will determine these results are beyond our ability to control or predict.
For additional discussion of risks, uncertainties and assumptions, see
“Risk Factors” included in Part I, Item 1A of our Annual Report on Form 10-K for
the fiscal year ended December 31, 2007 and in Part II, Item 1A of our quarterly
reports on Form 10-Q.
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.
Item
1. Financial Statements
Regency
Energy Partners LP
|
|
Condensed
Consolidated Balance Sheets
|
|
(in
thousands except unit data)
|
|
|
|
|
|
|
|
|
|
|
September
30, 2008
|
|
|
December
31, 2007*
|
|
|
|
(Unaudited)
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
Current
Assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
14,819 |
|
|
$ |
32,971 |
|
Restricted
cash
|
|
|
10,042 |
|
|
|
6,029 |
|
Trade
accounts receivable, net of allowance of $870 in 2008 and $61 in
2007
|
|
|
35,608 |
|
|
|
16,487 |
|
Accrued
revenues
|
|
|
131,058 |
|
|
|
117,622 |
|
Related
party receivables
|
|
|
1,508 |
|
|
|
61 |
|
Assets
from risk management activities
|
|
|
9,521 |
|
|
|
- |
|
Other
current assets
|
|
|
6,685 |
|
|
|
6,723 |
|
Total
current assets
|
|
|
209,241 |
|
|
|
179,893 |
|
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
|
|
|
|
|
|
|
Gathering
and transmission systems
|
|
|
616,187 |
|
|
|
635,206 |
|
Compression
equipment
|
|
|
754,710 |
|
|
|
145,555 |
|
Gas
plants and buildings
|
|
|
142,690 |
|
|
|
134,300 |
|
Other
property, plant and equipment
|
|
|
154,810 |
|
|
|
105,399 |
|
Construction-in-progress
|
|
|
127,687 |
|
|
|
33,552 |
|
Total
property, plant and equipment
|
|
|
1,796,084 |
|
|
|
1,054,012 |
|
Less
accumulated depreciation
|
|
|
(203,317 |
) |
|
|
(140,903 |
) |
Property,
plant and equipment, net
|
|
|
1,592,767 |
|
|
|
913,109 |
|
|
|
|
|
|
|
|
|
|
Other
Assets:
|
|
|
|
|
|
|
|
|
Intangible
assets, net of accumulated amortization of $18,866 in 2008 and $8,929 in
2007
|
|
|
205,447 |
|
|
|
77,804 |
|
Long-term
assets from risk management activities
|
|
|
14,424 |
|
|
|
- |
|
Goodwill
|
|
|
265,990 |
|
|
|
94,075 |
|
Other,
net of accumulated amortization of debt issuance costs of $4,601 in 2008
and $2,488 in 2007
|
|
|
16,974 |
|
|
|
13,529 |
|
Total
other assets
|
|
|
502,835 |
|
|
|
185,408 |
|
|
|
|
|
|
|
|
|
|
TOTAL
ASSETS
|
|
$ |
2,304,843 |
|
|
$ |
1,278,410 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES
& PARTNERS' CAPITAL
|
|
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
Trade
accounts payable
|
|
$ |
66,107 |
|
|
$ |
48,904 |
|
Accrued
cost of gas and liquids
|
|
|
104,648 |
|
|
|
96,026 |
|
Related
party payables
|
|
|
- |
|
|
|
50 |
|
Escrow
payable
|
|
|
10,042 |
|
|
|
6,029 |
|
Liabilities
from risk management activities
|
|
|
24,027 |
|
|
|
37,852 |
|
Other
current liabilities
|
|
|
31,845 |
|
|
|
9,397 |
|
Total
current liabilities
|
|
|
236,669 |
|
|
|
198,258 |
|
|
|
|
|
|
|
|
|
|
Long-term
liabilities from risk management activities
|
|
|
6,170 |
|
|
|
15,073 |
|
Other
long-term liabilities
|
|
|
15,591 |
|
|
|
15,393 |
|
Long-term
debt
|
|
|
1,006,500 |
|
|
|
481,500 |
|
Minority
interest in consolidated subsidiary
|
|
|
12,389 |
|
|
|
4,893 |
|
|
|
|
|
|
|
|
|
|
Commitments
and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners'
Capital:
|
|
|
|
|
|
|
|
|
Common
units (55,586,453 and 41,283,079 units authorized; 54,813,451 and
40,514,895 units issued and outstanding at September 30, 2008 and December
31, 2007)
|
|
|
766,658 |
|
|
|
490,351 |
|
Class
D common units (7,276,506 units authorized, issued and outstanding at
September 30, 2008)
|
|
|
224,902 |
|
|
|
- |
|
Class
E common units (4,701,034 units authorized, issued and outstanding at
December 31, 2007)
|
|
|
- |
|
|
|
92,962 |
|
Subordinated
units (19,103,896 units authorized, issued and outstanding at September
30, 2008 and December 31, 2007)
|
|
|
(609 |
) |
|
|
7,019 |
|
General
partner interest
|
|
|
29,232 |
|
|
|
11,286 |
|
Accumulated
other comprehensive income (loss)
|
|
|
7,341 |
|
|
|
(38,325 |
) |
Total
partners' capital
|
|
|
1,027,524 |
|
|
|
563,293 |
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND PARTNERS' CAPITAL
|
|
$ |
2,304,843 |
|
|
$ |
1,278,410 |
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed consolidated financial
statements
|
|
|
|
|
|
|
|
|
|
|
*
Recast to reflect an acquisition accounted for in a manner similar to a
pooling of interests.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regency
Energy Partners LP
|
|
Condensed
Consolidated Statements of Operations
|
|
Unaudited
|
|
(in
thousands except unit data and per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30, 2008
|
|
|
September
30, 2007 *
|
|
|
September
30, 2008
|
|
|
September
30, 2007 *
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
sales
|
|
$ |
323,411 |
|
|
$ |
175,107 |
|
|
$ |
922,872 |
|
|
$ |
538,360 |
|
NGL
sales
|
|
|
120,538 |
|
|
|
90,605 |
|
|
|
355,558 |
|
|
|
237,382 |
|
Gathering,
transportation and other fees, including related party amounts of $939,
$541, $2,865 and $1,325
|
|
|
74,267 |
|
|
|
30,478 |
|
|
|
206,429 |
|
|
|
69,553 |
|
Net
realized and unrealized gain (loss) from risk management
activities
|
|
|
6,817 |
|
|
|
(8,088 |
) |
|
|
(39,600 |
) |
|
|
(10,798 |
) |
Other
|
|
|
22,142 |
|
|
|
7,722 |
|
|
|
53,856 |
|
|
|
20,584 |
|
Total
revenues
|
|
|
547,175 |
|
|
|
295,824 |
|
|
|
1,499,115 |
|
|
|
855,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of sales, including related party amounts of $632, $656, $1,878 and
$13,829
|
|
|
408,165 |
|
|
|
234,946 |
|
|
|
1,168,441 |
|
|
|
696,644 |
|
Operation
and maintenance
|
|
|
33,688 |
|
|
|
18,134 |
|
|
|
95,049 |
|
|
|
41,031 |
|
General
and administrative
|
|
|
13,976 |
|
|
|
6,983 |
|
|
|
38,784 |
|
|
|
32,928 |
|
(Gain)
loss on asset sales, net
|
|
|
(34 |
) |
|
|
(777 |
) |
|
|
434 |
|
|
|
1,562 |
|
Management
services termination fee
|
|
|
- |
|
|
|
- |
|
|
|
3,888 |
|
|
|
- |
|
Transaction
expenses
|
|
|
2 |
|
|
|
- |
|
|
|
536 |
|
|
|
- |
|
Depreciation
and amortization
|
|
|
26,422 |
|
|
|
14,993 |
|
|
|
74,638 |
|
|
|
39,123 |
|
Total
operating costs and expenses
|
|
|
482,219 |
|
|
|
274,279 |
|
|
|
1,381,770 |
|
|
|
811,288 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
INCOME
|
|
|
64,956 |
|
|
|
21,545 |
|
|
|
117,345 |
|
|
|
43,793 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense, net
|
|
|
(16,072 |
) |
|
|
(10,894 |
) |
|
|
(48,261 |
) |
|
|
(41,740 |
) |
Loss
on debt refinancing
|
|
|
- |
|
|
|
(21,200 |
) |
|
|
- |
|
|
|
(21,200 |
) |
Other
income and deductions, net
|
|
|
118 |
|
|
|
713 |
|
|
|
450 |
|
|
|
951 |
|
Minority
interest
|
|
|
(162 |
) |
|
|
(156 |
) |
|
|
(165 |
) |
|
|
(130 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
(LOSS) BEFORE INCOME TAXES
|
|
|
48,840 |
|
|
|
(9,992 |
) |
|
|
69,369 |
|
|
|
(18,326 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax expense (benefit)
|
|
|
(67 |
) |
|
|
(160 |
) |
|
|
142 |
|
|
|
65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME (LOSS)
|
|
$ |
48,907 |
|
|
$ |
(9,832 |
) |
|
$ |
69,227 |
|
|
$ |
(18,391 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General
partner's interest in current period net income (loss), including
IDR
|
|
|
7,592 |
|
|
|
(256 |
) |
|
|
8,661 |
|
|
|
(433 |
) |
Beneficial
conversion feature for Class C common units
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,385 |
|
Beneficial
conversion feature for Class D common units
|
|
|
1,887 |
|
|
|
- |
|
|
|
5,312 |
|
|
|
- |
|
Limited
partners' interest in net income (loss)
|
|
$ |
39,428 |
|
|
$ |
(9,576 |
) |
|
$ |
55,254 |
|
|
$ |
(19,343 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
and Diluted earnings per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
allocated to common and subordinated units
|
|
$ |
39,428 |
|
|
$ |
(12,540 |
) |
|
$ |
55,254 |
|
|
$ |
(22,621 |
) |
Weighted
average number of common and subordinated units
outstanding
|
|
|
70,043,532 |
|
|
|
55,269,457 |
|
|
|
63,838,515 |
|
|
|
48,306,666 |
|
Basic
income (loss) per common and subordinated unit
|
|
$ |
0.56 |
|
|
$ |
(0.23 |
) |
|
$ |
0.87 |
|
|
$ |
(0.47 |
) |
Diluted
income (loss) per common and subordinated unit
|
|
$ |
0.53 |
|
|
$ |
(0.23 |
) |
|
$ |
0.85 |
|
|
$ |
(0.47 |
) |
Distributions
per unit
|
|
$ |
0.445 |
|
|
$ |
0.38 |
|
|
$ |
1.265 |
|
|
$ |
1.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class B common units
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
Weighted
average number of Class B common units outstanding
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
871,673 |
|
Income
per Class B common unit
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class C common units
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,385 |
|
Total
number of Class C common units outstanding
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,857,143 |
|
Income
per Class C common unit due to beneficial conversion
feature
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
0.48 |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class D common units
|
|
$ |
1,887 |
|
|
$ |
- |
|
|
$ |
5,312 |
|
|
$ |
- |
|
Total
number of Class D common units outstanding
|
|
|
7,276,506 |
|
|
|
- |
|
|
|
7,276,506 |
|
|
|
- |
|
Income
per Class D common unit due to beneficial conversion
feature
|
|
$ |
0.26 |
|
|
$ |
- |
|
|
$ |
0.73 |
|
|
$ |
- |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class E common units
|
|
$ |
- |
|
|
$ |
2,964 |
|
|
$ |
- |
|
|
$ |
3,278 |
|
Total
number of Class E common units outstanding
|
|
|
- |
|
|
|
4,701,034 |
|
|
|
4,701,034 |
|
|
|
4,701,034 |
|
Income
per Class E common unit
|
|
$ |
- |
|
|
$ |
0.63 |
|
|
$ |
- |
|
|
$ |
0.70 |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
2.06 |
|
|
$ |
- |
|
|
$ |
2.32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed consolidated financial
statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Recast to reflect an acquisition accounted for in a manner similar to a
pooling of interests.
|
|
|
|
|
|
|
|
|
|
Regency
Energy Partners LP
|
|
Condensed
Consolidated Statements of Comprehensive Income (Loss)
|
|
Unaudited
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30, 2008
|
|
September
30, 2007 *
|
|
September
30, 2008
|
|
September
30, 2007 *
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
48,907 |
|
|
$ |
(9,832 |
) |
|
$ |
69,227 |
|
|
$ |
(18,391 |
) |
Net
hedging amounts reclassified to earnings
|
|
|
14,787 |
|
|
|
4,641 |
|
|
|
40,389 |
|
|
|
7,457 |
|
Net
change in fair value of cash flow hedges
|
|
|
55,182 |
|
|
|
(11,694 |
) |
|
|
5,277 |
|
|
|
(33,072 |
) |
Comprehensive
income (loss)
|
|
$ |
118,876 |
|
|
$ |
(16,885 |
) |
|
$ |
114,893 |
|
|
$ |
(44,006 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed consolidated financial
statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Recast to reflect an acquisition accounted for in a manner similar to a
pooling of interests.
|
|
|
|
|
|
Regency
Energy Partners LP
|
|
Condensed
Consolidated Statements of Cash Flows
|
|
Unaudited
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
|
|
September
30, 2008
|
|
|
September
30, 2007 *
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
69,227 |
|
|
$ |
(18,391 |
) |
Adjustments
to reconcile net income (loss) to net cash flows provided by operating
activities:
|
|
|
|
|
|
Depreciation
and amortization, including debt issuance cost
amortization
|
|
|
76,751 |
|
|
|
40,627 |
|
Write-off
of debt issuance costs
|
|
|
- |
|
|
|
5,078 |
|
Equity
income and minority interest in earnings
|
|
|
165 |
|
|
|
130 |
|
Risk
management portfolio valuation changes
|
|
|
(1,007 |
) |
|
|
1,634 |
|
Loss
on asset sales
|
|
|
434 |
|
|
|
1,562 |
|
Unit
based compensation expenses
|
|
|
3,087 |
|
|
|
14,790 |
|
Gain
on insurance settlements
|
|
|
(3,282 |
) |
|
|
- |
|
Cash
flow changes in current assets and liabilities:
|
|
|
|
|
|
|
|
|
Trade
accounts receivable and accrued revenues
|
|
|
(11,084 |
) |
|
|
(14,857 |
) |
Other
current assets
|
|
|
38 |
|
|
|
251 |
|
Trade
accounts payable, accrued cost of gas and liquids, and related party
payables
|
|
|
(11,125 |
) |
|
|
15,171 |
|
Other
current liabilities
|
|
|
22,448 |
|
|
|
4,132 |
|
Other
assets and liabilities
|
|
|
3,628 |
|
|
|
(946 |
) |
Net
cash flows provided by operating activities
|
|
|
149,280 |
|
|
|
49,181 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(243,660 |
) |
|
|
(108,983 |
) |
Acquisitions
|
|
|
(577,344 |
) |
|
|
(34,844 |
) |
Acquisition
of investment in unconsolidated subsidiary, net of $100
cash
|
|
|
- |
|
|
|
(5,000 |
) |
Proceeds
from asset sales
|
|
|
696 |
|
|
|
11,723 |
|
Proceeds
from insurance settlements
|
|
|
3,282 |
|
|
|
- |
|
Net
cash flows used in investing activities
|
|
|
(817,026 |
) |
|
|
(137,104 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Net
borrowings under revolving credit facilities
|
|
|
525,000 |
|
|
|
33,300 |
|
Repayments
under credit facilities
|
|
|
- |
|
|
|
(50,000 |
) |
Repayments
of senior notes, net of debt issuance costs
|
|
|
- |
|
|
|
(192,500 |
) |
Partner
contributions
|
|
|
11,753 |
|
|
|
7,735 |
|
Partner
distributions
|
|
|
(86,448 |
) |
|
|
(56,208 |
) |
Proceeds
from option exercises
|
|
|
2,700 |
|
|
|
- |
|
Debt
issuance costs
|
|
|
(2,925 |
) |
|
|
(1,164 |
) |
FrontStreet
distributions
|
|
|
- |
|
|
|
(4,800 |
) |
FrontStreet
contributions
|
|
|
- |
|
|
|
10,895 |
|
Proceeds from
equity issuances, net of issuance costs
|
|
|
199,514 |
|
|
|
353,446 |
|
Net
cash flows provided by financing activities
|
|
|
649,594 |
|
|
|
100,704 |
|
|
|
|
|
|
|
|
|
|
Net
increase (decrease) in cash and cash equivalents
|
|
|
(18,152 |
) |
|
|
12,781 |
|
Cash
and cash equivalents at beginning of period
|
|
|
32,971 |
|
|
|
11,932 |
|
Cash
and cash equivalents at end of period
|
|
$ |
14,819 |
|
|
$ |
24,713 |
|
|
|
|
|
|
|
|
|
|
Supplemental
cash flow information:
|
|
|
|
|
|
|
|
|
Interest
paid, net of amounts capitalized
|
|
$ |
37,634 |
|
|
$ |
51,324 |
|
Income
taxes paid
|
|
|
596 |
|
|
|
- |
|
Non-cash
capital expenditures in accounts payable
|
|
|
24,871 |
|
|
|
3,359 |
|
Non-cash
capital expenditures for consolidation of investment in previously
unconsolidated subsidiary
|
|
|
- |
|
|
|
5,650 |
|
Non-cash
capital expenditure upon entering into a capital lease
obligation
|
|
|
- |
|
|
|
3,000 |
|
Issuance
of common units for an acquisition
|
|
|
219,590 |
|
|
|
19,724 |
|
Release of escrow payable from restricted cash
|
|
|
4,487 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed consolidated financial
statements
|
|
|
|
|
|
|
|
|
|
|
*
Recast to reflect an acquisition accounted for in a manner similar to a
pooling of interests.
|
|
|
|
|
|
Regency
Energy Partners LP
|
|
Condensed
Consolidated Statements of Partners' Capital
|
|
Unaudited
|
|
(in
thousands except unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
Class
D
|
|
Class
E
|
|
Subordinated
|
|
Common
Unitholders
|
|
Class
D Unitholders
|
|
Class
E Unitholders
|
|
|
Subordinated
Unitholders
|
|
|
General
Partner Interest
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
Total
|
|
Balance
- December 31, 2007 *
|
|
|
40,514,895 |
|
|
|
- |
|
|
4,701,034 |
|
|
19,103,896 |
|
$ |
490,351 |
|
|
$ |
- |
|
|
$ |
92,962 |
|
|
$ |
7,019 |
|
|
$ |
11,286 |
|
|
$ |
(38,325 |
) |
|
$ |
563,293 |
|
Issuance
of Class D common units
|
|
|
- |
|
|
|
7,276,506 |
|
|
- |
|
|
- |
|
|
- |
|
|
|
219,590 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
219,590 |
|
Issuance
of restricted common units and option exercises, net of
forfeitures
|
|
|
576,613 |
|
|
|
- |
|
|
- |
|
|
- |
|
|
2,700 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,700 |
|
Issuance
of common units
|
|
|
9,020,909 |
|
|
|
- |
|
|
- |
|
|
- |
|
|
199,514 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
199,514 |
|
Working
capital adjustment on FrontStreet
|
|
|
- |
|
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
|
(858 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(858 |
) |
Conversion
of Class E common units
|
|
|
4,701,034 |
|
|
|
- |
|
|
(4,701,034 |
) |
|
- |
|
|
92,104 |
|
|
|
- |
|
|
|
(92,104 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Unit
based compensation expenses
|
|
|
- |
|
|
|
- |
|
|
- |
|
|
- |
|
|
3,087 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,087 |
|
General
partner contributions
|
|
|
- |
|
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
11,753 |
|
|
|
- |
|
|
|
11,753 |
|
Partner
distributions
|
|
|
- |
|
|
|
- |
|
|
- |
|
|
- |
|
|
(59,814 |
) |
|
|
- |
|
|
|
- |
|
|
|
(24,166 |
) |
|
|
(2,468 |
) |
|
|
- |
|
|
|
(86,448 |
) |
Net
income
|
|
|
- |
|
|
|
- |
|
|
- |
|
|
- |
|
|
38,716 |
|
|
|
5,312 |
|
|
|
- |
|
|
|
16,538 |
|
|
|
8,661 |
|
|
|
- |
|
|
|
69,227 |
|
Net
hedging amounts reclassified to earnings
|
|
|
- |
|
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
40,389 |
|
|
|
40,389 |
|
Net
change in fair value of cash flow hedges
|
|
|
- |
|
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,277 |
|
|
|
5,277 |
|
Balance
- September 30, 2008
|
|
|
54,813,451 |
|
|
|
7,276,506 |
|
|
- |
|
|
19,103,896 |
|
$ |
766,658 |
|
|
$ |
224,902 |
|
|
$ |
- |
|
|
$ |
(609 |
) |
|
$ |
29,232 |
|
|
$ |
7,341 |
|
|
$ |
1,027,524 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed consolidated financial
statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*Recast
to reflect an acquisition accounted for in a manner similar to a pooling
of interests.
|
|
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, and its wholly owned and consolidated
subsidiaries. The Partnership and its subsidiaries are engaged in the
business of gathering, processing, contract compression, marketing, and
transporting natural gas and NGLs. The Partnership operates and
manages its business as three reportable segments: (a) gathering and processing,
(b) transportation, and (c) contract compression.
On
January 7, 2008, the Partnership acquired all of the outstanding equity and
minority interest (the “FrontStreet Acquisition”) of FrontStreet from ASC
and EnergyOne. FrontStreet owns a gas gathering system located in
Kansas and Oklahoma, which is operated by a third party.
The total
purchase price consisted of (a) 4,701,034 Class E common units of the
Partnership issued to ASC in exchange for its 95 percent interest and (b)
$11,752,000 in cash to EnergyOne in exchange for its five percent minority
interest and the termination of a management services contract valued at
$3,888,000. The Partnership financed the cash portion of the purchase
price with borrowings under its revolving credit facility.
In
connection with the FrontStreet Acquisition, the Partnership amended the
Partnership Agreement to create the Class E common units. The Class E
common units have the same terms and conditions as the Partnership’s common
units, except that the Class E common units are not entitled to participate in
earnings or distributions of operating surplus by the
Partnership. The Class E common units were issued in a private
placement conducted in accordance with the exemption from the registration
requirements of the Securities Act of 1933 as afforded by Section 4(2)
thereof. The Class E common units converted into common units on a
one-for-one basis on May 5, 2008.
Because
the acquisition of ASC’s 95 percent interest is a transaction between commonly
controlled entities (i.e., the buyer and the seller were each affiliates of
GECC), the Partnership accounted for this portion of the acquisition in a manner
similar to the pooling of interest method. Under this method of
accounting, the financial statements reflected historical balance sheet data for
both the Partnership and FrontStreet instead of reflecting the fair market value
of FrontStreet’s assets and liabilities. Further, certain transaction
costs that would otherwise be capitalized were expensed. Common
control between the Partnership and FrontStreet began on June 18,
2007. Accordingly, the statement of operations for the three and
nine months ending September 30, 2007 have been recast to include the
results of FrontStreet from June 18, 2007 through the end of the
period.
Conversely,
the acquisition of the five percent minority interest is a transaction between
independent parties, for which the Partnership applied the purchase method of
accounting. The final purchase price allocation, which management
expects to be completed before year end, may differ from the
estimates.
The
following table summarizes the book values of the assets acquired and
liabilities assumed at the date of common control, following the as-if pooled
method of accounting.
|
|
|
|
|
|
At
June 18, 2007
|
|
|
|
(in
thousands)
|
|
|
|
|
|
Current
assets
|
|
$ |
8,840 |
|
Property,
plant and equipment
|
|
|
91,556 |
|
Total
assets acquired
|
|
|
100,396 |
|
Current
liabilities
|
|
|
(12,556 |
) |
Net
book value of assets acquired
|
|
$ |
87,840 |
|
The
unaudited financial information as of, and for the three and nine months
ended, September 30, 2008 has been prepared on the same basis as the audited
consolidated financial statements included in the Partnership’s Annual Report on
Form 10-K, as amended by Form 8-K filed on May 9, 2008, for the year ended
December 31, 2007. In the opinion of the Partnership’s management,
such financial information reflects all adjustments necessary for a fair
presentation of the financial position and the results of operations for such
interim periods in accordance with GAAP. All intercompany items and
transactions have been eliminated in consolidation. Certain information and
footnote disclosures normally included in annual consolidated financial
statements prepared in accordance with GAAP have been omitted pursuant to the
rules and regulations of the SEC.
Use of Estimates. The
unaudited condensed consolidated financial statements have been prepared in
conformity with GAAP and, of necessity, include the use of estimates and
assumptions by management. Actual results could differ from these
estimates.
Intangible Assets. Intangible
assets, net consist of the following.
|
|
Permits
and Licenses
|
|
Customer
Contracts
|
|
Trade
Names
|
|
|
Total
|
|
|
|
(in
thousands)
|
|
Balance
at December 31,2007
|
|
$ |
9,368 |
|
|
$ |
68,436 |
|
|
$ |
- |
|
|
$ |
77,804 |
|
Additions
|
|
|
- |
|
|
|
102,480 |
|
|
|
35,100 |
|
|
|
137,580 |
|
Disposals
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Amortization
|
|
|
(590 |
) |
|
|
(7,680 |
) |
|
|
(1,667 |
) |
|
|
(9,937 |
) |
Balance
at September 30, 2008
|
|
$ |
8,778 |
|
|
$ |
163,236 |
|
|
$ |
33,433 |
|
|
$ |
205,447 |
|
The
weighted average amortization period for permits and licenses, customer
contracts, and trade names are 15, 20, and 15 years,
respectively. The expected amortization of the intangible assets for
each of the five succeeding years is as follows.
Year
ending December 31,
|
|
Total
|
|
|
|
(in
thousands)
|
|
2008
(remaining)
|
|
$ |
3,456 |
|
2009
|
|
|
12,358 |
|
2010
|
|
|
12,264 |
|
2011
|
|
|
10,950 |
|
2012
|
|
|
10,713 |
|
Recently Issued Accounting
Standards. 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 No. 159”), which permits entities to
measure many financial instruments and certain other assets and liabilities at
fair value on an instrument-by-instrument basis. The adoption of SFAS No.
159 in 2008 had no impact on the Partnership’s financial position, results
of operations or cash flows, as the Partnership has elected to continue valuing
its outstanding senior notes at historical cost.
In
December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS
No. 141(R)”), which significantly changes the accounting for business
acquisitions both during the period of the acquisition and in subsequent
periods. SFAS No. 141(R) is effective for fiscal years beginning
after December 15, 2008. Generally, the effects of SFAS No. 141(R)
will depend on future acquisitions.
In
December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS No. 160”),
which will significantly change the accounting and reporting related to
noncontrolling interests in a consolidated subsidiary. SFAS No. 160
is effective for fiscal years beginning after December 15, 2008. The
Partnership is currently evaluating the potential impacts on its financial
position, results of operations or cash flows as a result of the adoption of
this standard.
In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS No.
161”). SFAS No. 161 requires enhanced disclosures about derivative
and hedging activities. These enhanced disclosures will address (a)
how and why a company uses derivative instruments, (b) how derivative
instruments and related hedged items are accounted for under FASB Statement No.
133 and its related interpretations and (c) how derivative instruments and
related hedged items affect a company’s financial position, results of
operations and cash flows. SFAS No. 161 is effective for fiscal years
and interim periods beginning on or after November 15, 2008, with earlier
adoption allowed. The Partnership is currently evaluating the
potential impacts on its financial position, results of operations or cash flows
of the adoption of this standard.
In March
2008, the FASB issued EITF 07-4, “Application of the Two-Class Method under FASB
Statement No. 128 to Master Limited Partnerships” (“EITF No.
07-4”). EITF No. 07-4 defines how to allocate net income among the
various classes of equity, including incentive distribution rights, narrowing
the number of currently acceptable methods. The standard becomes
effective for financial statements issued for fiscal years beginning after
December 15, 2008, and interim periods within those fiscal
years. Earlier application is not permitted, and EITF No. 07-4 must
be applied retrospectively for all financial statements
presented. This new standard is not expected to have a material
impact on the Partnership’s financial position, results of operations or cash
flows.
In April
2008, FASB issued FSP No. 142-3, “Determination of the Useful Life of Intangible
Assets” (“FSP No. 142-3”), which amends the factors that should be considered in
developing renewal or extension assumptions used to determine the useful life of
intangible assets. The objective of FSP No. 142-3 is to better match
the useful life of intangible assets to the cash flow generated. FSP
No. 142-3 is effective for financial statements issued for fiscal years
beginning after December 15, 2008 and interim periods within those fiscal
years. Early adoption of this statement is not
permitted. The Partnership is currently evaluating the potential
impact of this standard on its financial position, results of operations and
cash flows.
In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles” (“SFAS No. 162”), which identifies the sources of
accounting principles and the framework for selecting the principles to be used
in the preparation of financial statements that are presented in conformity of
GAAP. SFAS No. 162’s effective date is November 15,
2008. The adoption of SFAS No. 162 is not expected to have a material
impact on the Partnership’s financial position, results of operations or cash
flows.
In June
2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted
in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF
03-6-1”). Based on this guidance, the Partnership will include
non-vested units granted under its LTIP in the basic earnings per unit
calculation. FSP EITF 03-6-1 is effective for financial statements
issued for fiscal years beginning after December 15, 2008, and interim periods
within those years. All prior-period earnings per unit data will be
adjusted. Early application is not permitted. This new
standard is not expected to have a material impact on the Partnership’s
financial position, results of operations or cash flows.
2. Income
(Loss) per Limited Partner Unit
In
connection with the CDM acquisition discussed below, the Partnership issued
7,276,506 Class D common units. At the commitment date, the sales
price of $30.18 per unit represented a $1.10 discount from the fair value of the
Partnership’s common units. Under EITF No. 98-5, “Accounting for
Convertible Securities with Beneficial Conversion Features or Contingently
Adjustable Conversion Ratios,” the discount represented a beneficial conversion
feature that is treated as a non-cash distribution for purposes of calculating
earnings per unit. The beneficial conversion feature is
reflected in income per unit using the effective yield method over the period
the Class D common units are outstanding, as indicated on the statements of
operations in the line item entitled “beneficial conversion feature for Class D
common units.”
The
following table provides a reconciliation of the numerator and denominator of
the basic and diluted earnings per unit computations for the three and
nine months ended September 30, 2008.
|
|
For
the Three Months Ended September 30, 2008
|
|
|
For
the Nine Months Ended September 30, 2008
|
|
|
|
Income
(Numerator)
|
|
|
Units
(Denominator)
|
|
|
Per-Unit
Amount
|
|
|
Income
(Numerator)
|
|
|
Units
(Denominator)
|
|
|
Per-Unit
Amount
|
|
|
|
(in
thousands except unit and per unit data)
|
|
Basic
Earnings per Unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited
partner's interest in net income
|
|
$ |
39,428 |
|
|
|
70,043,532 |
|
|
$ |
0.56 |
|
|
$ |
55,254 |
|
|
|
63,838,515 |
|
|
$ |
0.87 |
|
Effect
of Dilutive Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
unit options
|
|
|
- |
|
|
|
37,969 |
|
|
|
|
|
|
|
- |
|
|
|
111,134 |
|
|
|
|
|
Restricted
common units
|
|
|
- |
|
|
|
18,412 |
|
|
|
|
|
|
|
- |
|
|
|
50,657 |
|
|
|
|
|
Class
D common units
|
|
|
1,887 |
|
|
|
7,276,506 |
|
|
|
|
|
|
|
5,312 |
|
|
|
7,276,506 |
|
|
|
|
|
Diluted
Earnings per Unit
|
|
$ |
41,315 |
|
|
|
77,376,419 |
|
|
$ |
0.53 |
|
|
$ |
60,566 |
|
|
|
71,276,812 |
|
|
$ |
0.85 |
|
The
following data show securities that could potentially dilute earnings per unit
in the future that were not included in the computation of diluted EPS because
to do so would have been antidilutive for the periods presented.
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30, 2008
|
|
|
September
30, 2007
|
|
|
September
30, 2008
|
|
|
September
30, 2007
|
|
Restricted
common units
|
|
|
- |
|
|
|
386,500 |
|
|
|
- |
|
|
|
386,500 |
|
Common
unit options
|
|
|
- |
|
|
|
776,968 |
|
|
|
- |
|
|
|
776,968 |
|
3. Acquisitions
and Dispositions
CDM Resource Management, Ltd. On
January 15, 2008, the Partnership and an indirect wholly owned subsidiary
of the Partnership (“Merger Sub”) consummated an agreement and plan of merger
(the “Merger Agreement”) with CDM Resource Management, Ltd. CDM
provides its customers with turn-key natural gas contract compression services
to maximize their natural gas and crude oil production, throughput, and cash
flow in Texas, Louisiana, and Arkansas. The Partnership operates and
manages CDM as a separate reportable segment.
The total
purchase price paid by the Partnership for the partnership interests of CDM
consisted of (a) the issuance of an aggregate of 7,276,506 Class D common units
of the Partnership, which were valued at $219,590,000 and (b) an aggregate
of $478,445,000 in cash, $316,500,000 of which was used to retire CDM’s debt
obligations. Of the Class D common units issued, 4,197,303 Class D
common units were deposited with an escrow agent pursuant to an escrow
agreement. Such common units constitute security to the Partnership
for a period of one year after the closing with respect to any obligations under
the Merger Agreement, including obligations for breaches of representation,
warranties and covenants.
In
connection with the CDM merger, the Partnership amended the Partnership
Agreement to create the Class D common units. The Class D common
units have the same terms and conditions as the Partnership’s common units,
except that the Class D common units are not entitled to participate in
distributions of operating surplus by the Partnership. The Class D
common units automatically convert into common units on a one-for-one basis on
the close of business on the first business day after the record date for the
quarterly distribution on the common units for the quarter ending December 31,
2008. The Class D common units were issued in a private
placement conducted in accordance with the exemption from the registration
requirements of the Securities Act of 1933 under Section 4(2)
thereof.
The total
purchase price of $699,702,000, including direct transaction costs, was
allocated preliminarily as follows.
|
|
At
January 15, 2008
|
|
|
|
(in
thousands)
|
|
|
|
|
|
Current
assets
|
|
$ |
19,463 |
|
Other
assets
|
|
|
4,547 |
|
Gas
plants and buildings
|
|
|
1,528 |
|
Gathering
and transmission systems
|
|
|
421,160 |
|
Other
property, plant and equipment
|
|
|
2,728 |
|
Construction-in-progress
|
|
|
36,239 |
|
Identifiable
intangible assets
|
|
|
80,480 |
|
Goodwill
|
|
|
164,668 |
|
Assets
acquired
|
|
|
730,813 |
|
Current
liabilities
|
|
|
(31,054 |
) |
Other
liabilities
|
|
|
(57 |
) |
Net
assets acquired
|
|
$ |
699,702 |
|
The final
purchase price allocation, which management expects to be completed before year
end, may differ from the above estimates.
Nexus Gas Holdings,
LLC. On March 25, 2008, the Partnership acquired Nexus (“Nexus
Acquisition”) by merger for $88,486,000 in cash, including customary closing
adjustments. Nexus Gas Partners LLC, the sole member of Nexus prior to the
merger (“Nexus Member”), deposited $8,500,000 in an escrow account as security
to the Partnership for a period of one year against indemnification obligations
and any purchase price adjustment. The Partnership funded the Nexus
Acquisition through borrowings under its revolving credit
facility.
Upon
consummation of the Nexus Acquisition, the Partnership acquired Nexus’ rights
under a Purchase and Sale Agreement (the “Sonat Agreement”) between Nexus and
Sonat. Pursuant to the Sonat Agreement, Nexus will purchase 136 miles of
pipeline from Sonat (the “Sonat Asset Acquisition”) that could facilitate the
Nexus gathering system’s integration into the Partnership’s north Louisiana
asset base. The Sonat Asset Acquisition is subject to abandonment approval
and jurisdictional redetermination by the FERC, as well as customary closing
conditions. Upon closing of the Sonat Asset Acquisition, the Partnership
will pay Sonat $27,500,000, and, if the closing occurs on or prior to March 1,
2010, on certain terms and conditions as provided in the Merger Agreement, the
Partnership will make an additional payment of $25,000,000 to the Nexus
Member.
The total
purchase price of $88,486,000 was allocated preliminarily as
follows.
|
|
At
March 25, 2008
|
|
|
|
(in
thousands)
|
|
|
|
|
|
Current
assets
|
|
$ |
3,457 |
|
Buildings
|
|
|
13 |
|
Gathering
and transmission systems
|
|
|
16,960 |
|
Other
property, plant and equipment
|
|
|
4,440 |
|
Identifiable
intangible assets
|
|
|
57,100 |
|
Goodwill
|
|
|
7,187 |
|
Assets
acquired
|
|
|
89,157 |
|
Current
liabilities
|
|
|
(671 |
) |
Net
assets acquired
|
|
$ |
88,486 |
|
The final
purchase price allocation, which management expects to be completed before year
end, may differ from the above estimates.
The
following unaudited pro forma financial information has been prepared as if the
acquisitions of FrontStreet, CDM and Nexus had occurred as of the beginning of
the periods presented. Results for the nine months ended September
30, 2007 include the Partnership’s acquisition of Pueblo because that
acquisition occurred in April 2007. Such unaudited pro forma
financial information does not purport to be indicative of the results of
operations that would have been achieved if the transactions to which the
Partnership is giving pro forma effect actually occurred on the date referred to
above or the results of operations that may be expected in the
future.
|
|
Pro
Forma Results for the
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30, 2008
|
|
|
September
30, 2007
|
|
|
September
30, 2008
|
|
|
September
30, 2007
|
|
|
|
(in
thousands except unit and per unit data)
|
|
Revenue
|
|
$ |
547,175 |
|
|
$ |
322,915 |
|
|
$ |
1,506,322 |
|
|
$ |
953,445 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
48,907 |
|
|
$ |
(7,917 |
) |
|
$ |
71,041 |
|
|
$ |
(9,075 |
) |
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General
partner's interest in current period net income (loss), including
IDR
|
|
|
7,592 |
|
|
|
(217 |
) |
|
|
8,697 |
|
|
|
(246 |
) |
Beneficial
conversion feature for Class C common units
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,385 |
|
Beneficial
conversion feature for Class D common units
|
|
|
1,887 |
|
|
|
- |
|
|
|
5,312 |
|
|
|
- |
|
Limited
partners' interest in net income (loss)
|
|
$ |
39,428 |
|
|
$ |
(7,700 |
) |
|
$ |
57,032 |
|
|
$ |
(10,214 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
and Diluted earnings per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
allocated to common and subordinated units
|
|
$ |
39,428 |
|
|
$ |
(10,664 |
) |
|
$ |
57,032 |
|
|
$ |
(13,492 |
) |
Weighted
average number of common and subordinated units
outstanding
|
|
|
70,043,532 |
|
|
|
55,269,457 |
|
|
|
63,838,515 |
|
|
|
48,306,666 |
|
Basic
income (loss) per common and subordinated unit
|
|
$ |
0.56 |
|
|
$ |
(0.19 |
) |
|
$ |
0.89 |
|
|
$ |
(0.28 |
) |
Diluted
income (loss) per common and subordinated unit
|
|
$ |
0.53 |
|
|
$ |
(0.19 |
) |
|
$ |
0.87 |
|
|
$ |
(0.28 |
) |
Distributions
per unit
|
|
$ |
0.445 |
|
|
$ |
0.38 |
|
|
$ |
1.265 |
|
|
$ |
1.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class B common units
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
Weighted
average number of Class B common units outstanding
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
871,673 |
|
Income
per Class B common unit
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class C common units
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,385 |
|
Total
number of Class C common units outstanding
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,857,143 |
|
Income
per Class C common unit due to beneficial conversion
feature
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
0.48 |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class D common units
|
|
$ |
1,887 |
|
|
$ |
- |
|
|
$ |
5,312 |
|
|
$ |
- |
|
Total
number of Class D common units outstanding
|
|
|
7,276,506 |
|
|
|
- |
|
|
|
7,276,506 |
|
|
|
- |
|
Income
per Class D common unit due to beneficial conversion
feature
|
|
$ |
0.26 |
|
|
$ |
- |
|
|
$ |
0.73 |
|
|
$ |
- |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
allocated to Class E common units
|
|
$ |
- |
|
|
$ |
2,964 |
|
|
$ |
- |
|
|
$ |
3,278 |
|
Total
number of Class E common units outstanding
|
|
|
- |
|
|
|
4,701,034 |
|
|
|
4,701,034 |
|
|
|
4,701,034 |
|
Income
per Class E common unit
|
|
$ |
- |
|
|
$ |
0.63 |
|
|
$ |
- |
|
|
$ |
0.70 |
|
Distributions
per unit
|
|
$ |
- |
|
|
$ |
2.06 |
|
|
|
|
|
|
$ |
2.32 |
|
4. Risk
Management Activities
The net
fair value of the Partnership’s risk management activities constituted a net
liability of $6,252,000 at September 30, 2008. The Partnership
expects to reclassify $963,000 of net hedging gains to revenues or interest
expense from accumulated other comprehensive income (loss) in the next twelve
months. During the three and nine months ended September 30, 2008, the
Partnership recorded $19,917,000 and $2,090,000 of mark-to-market gain
and loss, respectively, for certain commodity hedges that do not qualify for
hedge accounting. In the three and nine months ended September 30,
2008, the Partnership recognized $1,512,000 and $1,998,000 of
ineffectiveness gains, respectively. In the three and nine months
ended September 30, 2008, the Partnership recorded in net realized and
unrealized gain (loss) from risk management activities a $162,000 and
$1,110,000, respectively, of gains associated with its credit risk
assessment in accordance with SFAS No. 157, “Fair Value Measurements” (“SFAS No.
157”).
The
Partnership’s hedging positions help reduce exposure to variability of future
commodity prices through 2010 and future interest rates on $300,000,000 of
long-term debt under its revolving credit facility through March 5, 2010, the
date the interest rate swaps expire.
Effective
June 19, 2007, the Partnership elected to account for all outstanding commodity
hedging instruments on a mark-to-market basis except for the portion pursuant to
which all NGL products for a particular year were hedged and the hedging
relationship was, for accounting purposes, effective. The Partnership
has a total of six hedging programs for a three-year period including
2008 through 2010 NGL hedging programs and West Texas Intermediate crude
oil hedging programs to hedge condensate for 2008 through 2010.
In March 2008,
the Partnership entered offsetting trades against its existing 2009 portfolio of
mark-to-market hedges, which it believes will substantially reduce the
volatility of its 2009 hedges. This group of trades, along with the
pre-existing 2009 portfolio, will continue to be accounted for on a
mark-to-market basis. Simultaneously, the Partnership executed
additional 2009 NGL swaps which were designated under SFAS No. 133 as cash flow
hedges. In May 2008, the Partnership entered into commodity
swaps to hedge a portion of its 2010 NGL commodity risk, except for ethane,
which are accounted for using mark-to-market accounting.
The
Partnership accounts for a portion of its 2008 and, prior to August 2008,
accounted for all of its 2009 West Texas Intermediate crude oil swaps using
mark-to-market accounting. In August 2008, the Partnership entered
into an offsetting trade against its existing 2009 West Texas Intermediate crude
oil swap to minimize the volatility of the original 2009
swap. Simultaneously, the Partnership executed an additional 2009
West Texas Intermediate crude oil swap, which was designated under SFAS No. 133
as a cash flow hedge. In May 2008, the Partnership entered into West
Texas Intermediate crude oil swap to hedge its 2010 condensate price risk, which
was designated as a cash flow hedge in June 2008.
On February 29, 2008, the
Partnership entered into two-year interest rate swaps related to $300,000,000 of
borrowings under its revolving credit facility, effectively locking the base
rate for these borrowings at 2.4 percent, plus the applicable margin
(2.0 percent as of September 30, 2008) through March 5,
2010. These interest rate swaps were designated as cash flow hedges
in March 2008.
5. Long-Term
Debt
Long-term
debt obligations of the Partnership are as follows:
|
|
|
|
|
|
|
|
|
September
30, 2008
|
|
|
December
31, 2007
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
Senior
notes
|
|
$ |
357,500 |
|
|
$ |
357,500 |
|
Revolving
loans
|
|
|
649,000 |
|
|
|
124,000 |
|
Total
|
|
|
1,006,500 |
|
|
|
481,500 |
|
Less:
current portion
|
|
|
- |
|
|
|
- |
|
Long-term
debt
|
|
$ |
1,006,500 |
|
|
$ |
481,500 |
|
|
|
|
|
|
|
|
|
|
Availability
under revolving credit facility:
|
|
|
|
|
|
|
|
|
Total
credit facility limit
|
|
$ |
900,000 |
|
|
$ |
500,000 |
|
Revolving
loans
|
|
|
(649,000 |
) |
|
|
(124,000 |
) |
Letters
of credit
|
|
|
(16,257 |
) |
|
|
(27,263 |
) |
Total
available
|
|
$ |
234,743 |
|
|
$ |
348,737 |
|
RGS
entered into Amendment No. 4 to its Fourth Amended and Restated Credit Facility
on January 15, 2008, thereby expanding its revolving credit facility to
$750,000,000. RGS also entered into Amendment No. 5 to its Fourth
Amended and Restated Credit Facility on February 13, 2008, expanding its
revolving credit facility to $900,000,000 and availability for letters of credit
to $100,000,000. The Partnership has the option to request an
additional $250,000,000 in revolving
and/or term loan commitments with ten business days written notice provided
that no event of default has occurred or would result due to such increase, and
all other additional conditions for the increase of the commitments set forth in
the credit facility have been met. These amendments did not
materially change other terms of the RGS revolving credit facility.
On
September 15, 2008, Lehman Brothers Holdings, Inc. (“Lehman”) filed a petition
in the United States Bankruptcy Court seeking relief under chapter 11 of the
United States Bankruptcy Code. Of the amount committed by Lehman, the
Partnership has borrowed all but $9,129,000. Lehman has declined
requests to honor its remaining commitment, effectively reducing the total size
of the Fourth Amended and Restated Credit Facility capacity to
$890,871,000. If we repay any of the $25,871,000 we have already borrowed
from Lehman, we will not be able to reborrow such amounts unless another
lender assumes Lehman's commitment.
The
outstanding balance of revolving debt under the credit facility bears interest
at LIBOR plus a margin or Alternative Base Rate (equivalent to the U.S. prime
lending rate) plus a margin, or a combination of both. The weighted average
interest rates for the revolving loans and senior notes, including interest rate
swap settlements, commitment fees, and amortization of debt issuance costs were
6.37 percent and 8.74 percent for the nine months ended September 30, 2008
and 2007, respectively and 6.15 percent and 8.80 percent for the three
months ended September 30, 2008 and 2007, respectively. The senior notes
bear interest at a fixed rate of 8.375 percent. The estimated fair market
value of the senior notes was $321,750,000 and $272,594,000 as of
September 30, 2008 and November 6, 2008, respectively.
The
senior notes are guaranteed by the Partnership’s subsidiaries (the “Guarantors”)
on December 12, 2006, the date the notes were issued. These note
guarantees are the joint and several obligations of the Guarantors. A
guarantor may not sell or otherwise dispose of all or substantially all of its
properties or assets if such sale would cause a default under the terms of the
senior notes. Events of default include nonpayment of principal or interest
when due; failure to comply with certain limits on the payment of distributions;
failure to make a change of control offer; failure to comply with reporting
requirements according to SEC rules and regulations; and defaults on the payment
of obligations under other indebtedness of $20,000,000 or more. Since
certain subsidiaries do not guarantee the senior notes, the condensed
consolidating financial statements of the guarantors and non-guarantors as of
and for the nine months ended September 30, 2008 are disclosed
below.
Condensed
Consolidating Balance Sheets
|
|
September
30, 2008
|
|
Unaudited
|
|
|
|
Guarantors
|
|
|
Non
Guarantors
|
|
|
Elimination
|
|
|
Consolidated
|
|
ASSETS
|
|
(in
thousands)
|
|
Total
current assets
|
|
$ |
191,412 |
|
|
$ |
17,829 |
|
|
$ |
- |
|
|
$ |
209,241 |
|
Property,
plant and equipment, net
|
|
|
1,500,197 |
|
|
|
92,570 |
|
|
|
- |
|
|
|
1,592,767 |
|
Total
other assets
|
|
|
502,835 |
|
|
|
- |
|
|
|
- |
|
|
|
502,835 |
|
TOTAL
ASSETS
|
|
$ |
2,194,444 |
|
|
$ |
110,399 |
|
|
$ |
- |
|
|
$ |
2,304,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
& PARTNERS' CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
current liabilities
|
|
$ |
232,502 |
|
|
$ |
4,167 |
|
|
$ |
- |
|
|
$ |
236,669 |
|
Long-term
liabilities from risk management activities
|
|
|
6,170 |
|
|
|
- |
|
|
|
- |
|
|
|
6,170 |
|
Other
long-term liabilities
|
|
|
15,591 |
|
|
|
- |
|
|
|
- |
|
|
|
15,591 |
|
Long-term
debt
|
|
|
1,006,500 |
|
|
|
- |
|
|
|
- |
|
|
|
1,006,500 |
|
Minority
interest
|
|
|
12,389 |
|
|
|
- |
|
|
|
- |
|
|
|
12,389 |
|
Partners'
capital
|
|
|
921,292 |
|
|
|
106,232 |
|
|
|
- |
|
|
|
1,027,524 |
|
TOTAL
LIABILITIES & PARTNERS' CAPITAL
|
|
$ |
2,194,444 |
|
|
$ |
110,399 |
|
|
$ |
- |
|
|
$ |
2,304,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed
Consolidating Statements of Operations
|
|
For
the Nine Months Ended September 30, 2008
|
|
Unaudited
|
|
|
|
Guarantors
|
|
|
Non
Guarantors
|
|
|
Elimination
|
|
|
Consolidated
|
|
|
|
(in
thousands)
|
|
Total
revenues
|
|
$ |
1,465,086 |
|
|
$ |
34,029 |
|
|
$ |
- |
|
|
$ |
1,499,115 |
|
Total
operating costs and expenses
|
|
|
1,353,211 |
|
|
|
28,559 |
|
|
|
- |
|
|
|
1,381,770 |
|
OPERATING
INCOME
|
|
|
111,875 |
|
|
|
5,470 |
|
|
|
- |
|
|
|
117,345 |
|
Interest
expense, net
|
|
|
(48,261 |
) |
|
|
- |
|
|
|
- |
|
|
|
(48,261 |
) |
Other
income and deductions, net
|
|
|
514 |
|
|
|
(64 |
) |
|
|
- |
|
|
|
450 |
|
Minority
interest
|
|
|
(165 |
) |
|
|
- |
|
|
|
- |
|
|
|
(165 |
) |
INCOME
BEFORE INCOME TAXES
|
|
|
63,963 |
|
|
|
5,406 |
|
|
|
- |
|
|
|
69,369 |
|
Income
tax expense
|
|
|
142 |
|
|
|
- |
|
|
|
- |
|
|
|
142 |
|
NET
INCOME
|
|
$ |
63,821 |
|
|
$ |
5,406 |
|
|
$ |
- |
|
|
$ |
69,227 |
|
Condensed
Consolidating Statements of Cash Flow
|
|
For
the Nine Months Ended September 30, 2008
|
|
Unaudited
|
|
|
|
Guarantors
|
|
|
Non
Guarantors
|
|
|
Elimination
|
|
|
Consolidated
|
|
|
|
(in
thousands)
|
|
Net
cash flows provided by (used in) operating activities
|
|
$ |
151,061 |
|
|
$ |
(1,781 |
) |
|
$ |
- |
|
|
$ |
149,280 |
|
Net
cash flows used in investing activities
|
|
|
(813,658 |
) |
|
|
(3,368 |
) |
|
|
- |
|
|
|
(817,026 |
) |
Net
cash flows provided by financing activities
|
|
|
649,594 |
|
|
|
- |
|
|
|
- |
|
|
|
649,594 |
|
6. Equity
Offering
On August
1, 2008, the Partnership sold 9,020,909 common units for an average price of
$22.18 per unit under the Partnership’s universal shelf registration
statement. The Partnership received $204,133,000 in proceeds,
inclusive of the General Partner’s proportionate capital contribution of
$4,082,653. The net proceeds were used to repay indebtedness under
the Partnership’s revolving credit facility. An affiliate of GECC
purchased 2,272,727 of these common units. As of September 30, 2008,
the Partnership has incurred $34,000 in costs related to this equity
offering.
7. Commitments
and Contingencies
Legal. The Partnership
is involved in various 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 Partnership’s
business, financial condition, results of operations or cash flows.
Contingent Purchase of Sonat
Assets. In March of 2008, the Partnership, through the Nexus
Acquisition, obtained the rights to a contingent commitment to purchase 136
miles of pipeline that could facilitate the Nexus gathering system’s integration
into the Partnership’s north Louisiana asset base. The purchase commitment
is contingent upon the FERC declaring that the pipeline is no longer subject to
its jurisdiction, together with approval of the current owner’s abandonment and
other customary closing conditions. In the event that all
contingencies are satisfactorily resolved, the Partnership will pay Sonat
$27,500,000. Furthermore, if the closing occurs on or prior to March
1, 2010, the Partnership will pay an additional $25,000,000 to the sellers,
subject to certain terms and conditions.
On April
3, 2008, Sonat filed an application with the FERC seeking authorization to
abandon by sale to Nexus 136 miles of pipeline and related
facilities. The application also requested a determination that the
facilities being sold to Nexus be considered non-jurisdictional, with certain
facilities being gathering and certain facilities being intrastate
transmission. Four producers submitted letters in support of the
application and several Sonat shippers protested the application. The
matter is currently pending.
Escrow Payable. At
September 30, 2008, $1,507,000 remained in escrow pending the
completion by El Paso of environmental remediation projects pursuant to the
purchase and sale agreement (“El Paso PSA”) related to assets in north Louisiana
and the mid-continent area. In the El Paso PSA, El Paso indemnified
the predecessor of our operating partnership, RGS, against losses arising from
pre-closing and known environmental liabilities subject to a limit of
$84,000,000 and certain deductible limits. Upon completion of a Phase
II environmental study, the Partnership notified El Paso of remediation
obligations amounting to $1,800,000 with respect to known environmental matters
and $3,600,000 with respect to pre-closing environmental
liabilities.
In
January 2008, pursuant to authorization by the Board of Directors of the General
Partner, the Partnership agreed to settle the El Paso environmental
remediation. Under the settlement, El Paso will clean up and obtain
“no further action” letters from the relevant state agencies for three
Partnership-owned facilities. El Paso is not obligated to clean up
properties leased by the Partnership, but it indemnified the Partnership for
pre-closing environmental liabilities. All sites for which the
Partnership made environmental claims against El Paso are either addressed in
the settlement or have already been resolved. In May 2008, the
Partnership released all but $1,500,000 from the escrow fund maintained to
secure El Paso’s obligations. This amount will be further reduced
under a specified schedule as El Paso completes its cleanup obligations and the
remainder will be released upon completion.
Nexus Escrow. At
September 30, 2008, $8,535,000 is included in an escrow account as security to
the Partnership for a period of one year against indemnification obligations and
any purchase price adjustments related to the Nexus Acquisition.
Environmental. A
Phase I environmental study was performed on certain assets located in west
Texas in connection with the pre-acquisition due diligence process in 2004.
Most of the identified environmental contamination had either been
remediated or was being remediated by the previous owners or operators of the
properties. The aggregate potential environmental remediation costs
at specific locations were estimated to range from $1,900,000 to
$3,100,000. No governmental agency has required the Partnership to
undertake these remediation efforts. Management believes that the
likelihood that it will be liable for any significant potential remediation
liabilities identified in the study is remote. Separately, the Partnership
acquired an environmental pollution liability insurance policy in connection
with the acquisition to cover any undetected or unknown pollution discovered in
the future. The policy covers clean-up costs and damages to third parties,
and has a 10-year term (expiring 2014) with a $10,000,000 limit subject to
certain deductibles. No claims have been made.
TCEQ Notice of
Enforcement. On February 15, 2008,
the TCEQ issued a NOE concerning one of the Partnership’s processing plants
located in McMullen County, Texas (the “Plant”). The NOE alleges
that, between March 9, 2006, and May 8, 2007, the Plant experienced 15 emission
events of various durations from four hours to 41 days, which were not reported
to TCEQ and other agencies within 24 hours of occurrence. On April 3,
2008, TCEQ presented the Partnership with a written offer to settle the
allegation in the NOE in exchange for payment of an administrative penalty of
$480,000. The Partnership was unable to settle this matter on a
satisfactory basis and the TCEQ has referred the matter for further
proceedings.
RIGS FERC
Petition. On April 29, 2008, RIGS filed a petition with the
FERC seeking approval to maintain its maximum Section 311 transportation rates
for firm and interruptible services as follows: Firm Service –
reservation fee of $4.5625 per MMBtu monthly ($0.15 per MMBtu daily) and
commodity fee of $0.05 per MMBtu; Interruptible Service – transportation fee of
$0.20 per MMBtu; and Fuel Retention - up to two percent of
receipts. The rate filing was required by a FERC Letter Order issued
on September 26, 2005, which approved a settlement in which RIGS agreed to
justify its existing rates or establish new rates for Section 311 services by
May 1, 2008.
RIGS
reached a settlement with FERC Staff on the 2008 petition, and on September 23,
2008, the FERC approved the settlement. The settlement provided for
the continuation of RIGS existing maximum transportation rates and a reduction
in RIGS’ maximum fuel retention to one and a one-half percent effective May 1,
2008. The settlement permits RIGS’ maximum fuel retention rate to
increase to two percent when new compression is added to the RIGS
system. As part of the settlement, RIGS also agreed to fully
support its requested maximum fuel retention percentage in its next rate filing
and to re-justify or establish new rates for Section 311 service by May 1,
2011. The triennial rate review requirement is a standard settlement
provision in most intrastate pipeline rate proceedings for Section 311
service.
Keyes
Litigation. In August 2008, Keyes Helium Company, LLC
(“Keyes”) filed suit against Regency Gas Services LP, the Partnership, and the
General Partner. Keyes entered into an output contract with the
Partnership’s predecessor in 1996 under which it purchased all of the helium
produced at the Lakin processing plant in southwest Kansas. In
September 2004, the Partnership decided to shut down the Lakin plant and
contract with a third party for the processing of volumes processed at Lakin, as
a result of which the Partnership no longer delivered any helium to
Keyes. As a result, Keyes alleges it is entitled to an unspecified
amount of damages for the costs of covering its purchases of
helium. The Partnership filed an answer to this lawsuit and plans to
defend itself vigorously.
Kansas State Severance
Tax. In August 2008, a customer began remitting severance tax
to the state of Kansas based on the value of condensate purchased from one of
the Partnership’s Mid-Continent gathering fields and deducting the tax from its
payments to the Partnership. The Kansas Department of Revenue advised
the customer that it was appropriate to remit such taxes and withhold the taxes
from its payments to the Partnership, absent an order or legal opinion from the
Kansas Department of Revenue stating otherwise. The Partnership has
requested a determination from the Kansas Department of Revenue regarding the
matter since severance taxes were already paid on the gas from which the
condensate is collected and no additional tax is due. If the Kansas
Department of Revenue determines that the condensate sales are taxable, then the
Partnership may be subject to additional taxes for past and future condensate
sales.
Purchase
Commitments. At September 30, 2008, the Partnership has
purchase obligations totaling $428,454,000, of which $148,924,000 relate to the
purchase of major compression components unrelated to the expansion of RIGS,
referred to in this document as the Haynesville Expansion Project, that extend
until the year ending December 31, 2010 and $279,530,000 of commitments related
to the Haynesville Expansion Project that extend until the year ending December
31, 2009. Some of these commitments have cancellation
provisions.
8. Related
Party Transactions
The
employees operating the assets of the Partnership and its subsidiaries and
substantially all those providing staff and support services are employees of
the General Partner and other affiliates of the Partnership. Pursuant
to the Partnership Agreement, the General Partner receives a monthly
reimbursement for all direct and indirect expenses that it incurs on behalf of
the Partnership. Reimbursements of $7,284,000 and $7,169,000 were recorded in
the Partnership’s financial statements during the three months ended September
30, 2008 and 2007, respectively, and reimbursements of $22,605,000 and
$20,408,000 were recorded in the Partnership’s financial statements during the
nine months ended September 30, 2008 and 2007, respectively, as operating
expenses or general and administrative expenses, as appropriate.
In
conjunction with distributions by the Partnership to its limited and general
partner interests, GE EFS and affiliates received cash distributions of
$25,396,000 and $7,212,000 during the nine months ended September 30, 2008
and 2007, respectively, as result of their ownership interests in the
Partnership.
In
conjunction with distributions by the Partnership to its limited and general
partner interests, HM Capital Partners and affiliates received cash
distributions of $10,308,000 and $21,215,000 during the nine months ended
September 30, 2008 and 2007, respectively, as a result of their ownership
interests in the Partnership. In September 2008, HM Capital Partners
and affiliates sold 7,100,000 common units, reducing their ownership percentage
to an amount less than ten percent of the Partnership’s outstanding common
units. As a result of this sale, HM Capital Partners is no longer a related
party of the Partnership.
In
conjunction with distributions by the Partnership to its limited and general
partner interests, certain members of management received cash distributions of
$1,382,000 in the nine months ended September 30, 2008 as a result of
their ownership interests in the Partnership.
9. Segment
Information
The
Partnership has three reportable segments: (a) gathering and processing, (b)
transportation, and (c) contract compression. Gathering and
processing involves collecting raw natural gas from producer wells and
transporting it to treating plants where water and other impurities such as
hydrogen sulfide and carbon dioxide are removed. Treated gas is then
processed to remove the natural gas liquids. The treated and processed
natural gas is then transported to market separately from the natural gas
liquids. Revenues and the associated cost of sales from the gathering and
processing segment directly expose the Partnership to commodity price risk,
which is managed through derivative contracts and other measures. The
Partnership aggregates the results of its gathering and processing activities
across five geographic regions into a single reporting segment.
The
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 Partnership’s
gathering and processing facilities in the same area and those transactions
create a portion of the intersegment revenues shown in the table
below.
The
contract compression segment includes designing, sourcing, owning, insuring,
installing, operating, servicing, repairing, and maintaining compressors and
related equipment, with a focus on meeting the complex requirements of
field-wide compression applications, as opposed to targeting the compression
needs of individual wells within a field. These field-wide applications
include compression for natural gas gathering, natural gas lift for crude oil
production and natural gas processing. Revenues in this segment are
fee-based, with minimal direct exposure to commodity price risk. The
contract compression operations are primarily located in Texas, Louisiana, and
Arkansas. The contract compression segment also provides services to
certain operations in the gathering and processing segment, creating a portion
of the intersegment revenues shown in the table below.
Management
evaluates the performance of each segment and makes capital allocation decisions
through the separate consideration of segment margin and operation and
maintenance expenses. Segment margin, for the gathering and
processing and for the transportation segments, is defined as total revenues,
including service fees, less cost of sales. In the contract compression
segment, segment margin is defined as revenues minus direct costs, which
primarily consist of compressor repairs. Management believes segment margin
is an important measure because it directly relates to volume, commodity price
changes and revenue generating horsepower. Operation and maintenance
expenses are a separate measure used by management to evaluate performance of
field operations. Direct labor, insurance, property taxes, repair and
maintenance, utilities and contract services comprise the most significant
portion of operation and maintenance expenses. These expenses fluctuate
depending on the activities performed during a specific period. The
Partnership does not deduct operation and maintenance expenses from total
revenues in calculating segment margin because management separately evaluates
commodity volume and price changes in segment margin.
Results
for each statement of operations period, together with amounts related to
balance sheets for each segment, are shown below.
|
|
Gathering
and Processing
|
|
|
Transportation
|
|
|
Contract
Compression
|
|
|
Corporate
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(in
thousands)
|
|
External
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ended September 30, 2008
|
|
$
|
377,482 |
|
|
$ |
133,620 |
|
|
$ |
36,073 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
547,175 |
|
For
the three months ended September 30, 2007
|
|
|
199,717 |
|
|
|
96,107 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
295,824 |
|
For
the nine months ended September 30, 2008
|
|
|
977,773 |
|
|
|
427,326 |
|
|
|
94,016 |
|
|
|
- |
|
|
|
- |
|
|
|
1,499,115 |
|
For
the nine months ended September 30, 2007
|
|
|
590,796 |
|
|
|
264,285 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
855,081 |
|
Intersegment
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ended September 30, 2008
|
|
|
- |
|
|
|
64,685 |
|
|
|
- |
|
|
|
- |
|
|
|
(64,685 |
) |
|
|
- |
|
For
the three months ended September 30, 2007
|
|
|
- |
|
|
|
23,782 |
|
|
|
- |
|
|
|
- |
|
|
|
(23,782 |
) |
|
|
- |
|
For
the nine months ended September 30, 2008
|
|
|
- |
|
|
|
147,440 |
|
|
|
- |
|
|
|
- |
|
|
|
(147,440 |
) |
|
|
- |
|
For
the nine months ended September 30, 2007
|
|
|
- |
|
|
|
71,783 |
|
|
|
- |
|
|
|
- |
|
|
|
(71,783 |
) |
|
|
- |
|
Cost
of Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ended September 30, 2008
|
|
|
290,840 |
|
|
|
178,587 |
|
|
|
3,423 |
|
|
|
- |
|
|
|
(64,685 |
) |
|
|
408,165 |
|
For
the three months ended September 30, 2007
|
|
|
154,127 |
|
|
|
104,601 |
|
|
|
- |
|
|
|
- |
|
|
|
(23,782 |
) |
|
|
234,946 |
|
For
the nine months ended September 30, 2008
|
|
|
790,635 |
|
|
|
516,551 |
|
|
|
8,695 |
|
|
|
- |
|
|
|
(147,440 |
) |
|
|
1,168,441 |
|
For
the nine months ended September 30, 2007
|
|
|
475,329 |
|
|
|
293,098 |
|
|
|
- |
|
|
|
- |
|
|
|
(71,783 |
) |
|
|
696,644 |
|
Segment
Margin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ended September 30, 2008
|
|
|
86,642 |
|
|
|
19,718 |
|
|
|
32,650 |
|
|
|
- |
|
|
|
- |
|
|
|
139,010 |
|
For
the three months ended September 30, 2007
|
|
|
45,590 |
|
|
|
15,288 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
60,878 |
|
For
the nine months ended September 30, 2008
|
|
|
187,138 |
|
|
|
58,215 |
|
|
|
85,321 |
|
|
|
- |
|
|
|
- |
|
|
|
330,674 |
|
For
the nine months ended September 30, 2007
|
|
|
115,467 |
|
|
|
42,970 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
158,437 |
|
Operation
and Maintenance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ended September 30, 2008
|
|
|
25,218 |
|
|
|
(927 |
) |
|
|
9,397 |
|
|
|
- |
|
|
|
- |
|
|
|
33,688 |
|
For
the three months ended September 30, 2007
|
|
|
16,688 |
|
|
|
1,446 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
18,134 |
|
For
the nine months ended September 30, 2008
|
|
|
63,656 |
|
|
|
1,931 |
|
|
|
29,462 |
|
|
|
- |
|
|
|
- |
|
|
|
95,049 |
|
For
the nine months ended September 30, 2007
|
|
|
36,285 |
|
|
|
4,746 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
41,031 |
|
Depreciation
and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the three months ended September 30, 2008
|
|
|
15,114 |
|
|
|
3,532 |
|
|
|
7,537 |
|
|
|
239 |
|
|
|
- |
|
|
|
26,422 |
|
For
the three months ended September 30, 2007
|
|
|
11,218 |
|
|
|
3,447 |
|
|
|
- |
|
|
|
328 |
|
|
|
- |
|
|
|
14,993 |
|
For
the nine months ended September 30, 2008
|
|
|
43,028 |
|
|
|
10,519 |
|
|
|
20,370 |
|
|
|
721 |
|
|
|
- |
|
|
|
74,638 |
|
For
the nine months ended September 30, 2007
|
|
|
28,146 |
|
|
|
10,054 |
|
|
|
- |
|
|
|
923 |
|
|
|
- |
|
|
|
39,123 |
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2008
|
|
|
1,080,035 |
|
|
|
331,369 |
|
|
|
848,333 |
|
|
|
45,106 |
|
|
|
- |
|
|
|
2,304,843 |
|
December
31, 2007
|
|
|
886,477 |
|
|
|
329,862 |
|
|
|
- |
|
|
|
62,071 |
|
|
|
- |
|
|
|
1,278,410 |
|
Goodwill
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September
30, 2008
|
|
|
67,079 |
|
|
|
34,243 |
|
|
|
164,668 |
|
|
|
- |
|
|
|
- |
|
|
|
265,990 |
|
December
31, 2007
|
|
|
59,832 |
|
|
|
34,243 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
94,075 |
|
Expenditures
for Long-Lived Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the nine months ended September 30, 2008
|
|
|
108,330 |
|
|
|
92 |
|
|
|
133,367 |
|
|
|
1,871 |
|
|
|
- |
|
|
|
243,660 |
|
For
the nine months ended September 30, 2007
|
|
|
100,012 |
|
|
|
8,269 |
|
|
|
- |
|
|
|
702 |
|
|
|
- |
|
|
|
108,983 |
|
The table
below provides a reconciliation of total segment margin to net income (loss),
the most comparable GAAP measure.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30, 2008
|
|
|
September
30, 2007
|
|
|
September
30, 2008
|
|
|
September
30, 2007
|
|
|
|
(in
thousands)
|
|
Net
income (loss)
|
|
$ |
48,907 |
|
|
$ |
(9,832 |
) |
|
$ |
69,227 |
|
|
$ |
(18,391 |
) |
Add
(deduct):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
33,688 |
|
|
|
18,134 |
|
|
|
95,049 |
|
|
|
41,031 |
|
General
and administrative
|
|
|
13,976 |
|
|
|
6,983 |
|
|
|
38,784 |
|
|
|
32,928 |
|
Loss
(gain) on assets sales, net
|
|
|
(34 |
) |
|
|
(777 |
) |
|
|
434 |
|
|
|
1,562 |
|
Management
services termination fee
|
|
|
- |
|
|
|
- |
|
|
|
3,888 |
|
|
|
- |
|
Transaction
expenses
|
|
|
2 |
|
|
|
- |
|
|
|
536 |
|
|
|
- |
|
Depreciation
and amortization
|
|
|
26,422 |
|
|
|
14,993 |
|
|
|
74,638 |
|
|
|
39,123 |
|
Interest
expense, net
|
|
|
16,072 |
|
|
|
10,894 |
|
|
|
48,261 |
|
|
|
41,740 |
|
Loss
on debt refinancing
|
|
|
- |
|
|
|
21,200 |
|
|
|
- |
|
|
|
21,200 |
|
Minority
interest |
|
|
162 |
|
|
|
156 |
|
|
|
165 |
|
|
|
130 |
|
Other
income and deductions, net
|
|
|
(118 |
) |
|
|
(713 |
) |
|
|
(450 |
) |
|
|
(951 |
) |
Income
tax expense (benefit)
|
|
|
(67 |
) |
|
|
(160 |
) |
|
|
142 |
|
|
|
65 |
|
Total
segment margin
|
|
$ |
139,010 |
|
|
$ |
60,878 |
|
|
$ |
330,674 |
|
|
$ |
158,437 |
|
10. Equity-Based
Compensation
In
December 2005, the General Partner approved a long-term incentive plan (“LTIP”)
for the Partnership’s employees, directors, and consultants covering an
aggregate of 2,865,584 common units. LTIP awards generally vest on the
basis of one-fourth of the award each year. Excluding forfeitures, the
Partnership expects to recognize $20,561,000 of compensation expense related to
the non-vested grants over a weighted average period of three years and two
months. All outstanding options are vested and expire ten years after
the grant date.
The
Partnership makes 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 exercise of the common unit options, the Partnership
anticipates settling these obligations with common units. In the nine
months ended September 30, 2008, two former executives of the Partnership
exercised 135,000 unit options.
The
common unit options and restricted (non-vested) unit activity for the nine
months ended September 30, 2008 are as follows.
Common
Unit Options
|
|
Units
|
|
|
Weighted
Average Exercise Price
|
|
|
Weighted
Average Contractual Term (Years)
|
|
|
Aggregate
Intrinsic Value * (in thousands)
|
|
Outstanding
at beginning of period
|
|
|
738,668 |
|
|
$ |
21.05 |
|
|
|
|
|
|
|
Granted
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
Exercised
|
|
|
(245,150 |
) |
|
|
20.55 |
|
|
|
|
|
$ |
1,719 |
|
Forfeited
or expired
|
|
|
(15,400 |
) |
|
|
22.50 |
|
|
|
|
|
|
- |
|
Outstanding
at end of period
|
|
|
478,118 |
|
|
|
21.25 |
|
|
|
7.52 |
|
|
|
- |
|
Exercisable
at end of period
|
|
|
478,118 |
|
|
|
21.25 |
|
|
|
|
|
|
|
|
|
*
Intrinsic value equals the closing market price of a unit less the option strike
price, multiplied by the number of unit options outstanding as of the end
of the period presented. Unit options with an exercise
price greater than the end of the period closing market price are
excluded. The intrinsic value for exercised common unit options is
calculated by multiplying the difference between the market price on the date of
exercise and option strike price by the number of common unit options
exercised.
Restricted
(Non-Vested) Units
|
|
Units
|
|
|
Weighted
Average Grant Date Fair Value
|
|
Outstanding
at beginning of period
|
|
|
397,500 |
|
|
$ |
31.62 |
|
Granted
|
|
|
473,300 |
|
|
|
28.15 |
|
Vested
|
|
|
(85,000 |
) |
|
|
31.75 |
|
Forfeited
or expired
|
|
|
(59,500 |
) |
|
|
30.85 |
|
Outstanding
at end of period
|
|
|
726,300 |
|
|
|
29.41 |
|
11. Fair
Value Measures
On
January 1, 2008, the Partnership adopted the provisions of SFAS No. 157 for
financial assets and liabilities. SFAS No. 157 became effective for
financial assets and liabilities on January 1, 2008. On January 1, 2009,
the Partnership will apply the provisions of SFAS No. 157 for non-recurring fair
value measurements of non-financial assets and liabilities, such as goodwill,
indefinite-lived intangible assets, property, plant and equipment and asset
retirement obligations. SFAS No. 157 defines fair value, thereby
eliminating inconsistencies in guidance found in various prior accounting
pronouncements, and increases disclosures surrounding fair value
calculations.
SFAS No.
157 establishes a three-tiered fair value hierarchy that prioritizes inputs to
valuation techniques used in fair value calculations. The three levels of
inputs are defined as follows:
·
|
Level
1 — unadjusted quoted prices for identical assets or liabilities in active
markets accessible by us;
|
·
|
Level
2 — inputs that are observable in the marketplace other than those inputs
classified as Level 1; and
|
·
|
Level
3 — inputs that are unobservable in the marketplace and significant to the
valuation.
|
SFAS No.
157 encourages entities to maximize the use of observable inputs and
minimize the use of unobservable inputs. If a financial instrument uses
inputs that fall in different levels of the hierarchy, the instrument will be
categorized based upon the lowest level of input that is significant to the fair
value calculation.
The
Partnership’s financial assets and liabilities measured at fair value on a
recurring basis are risk management assets and liabilities related to
interest rate and commodity swaps. Risk management assets and
liabilities are valued using discounted cash flow techniques. These
techniques incorporate Level 1 and Level 2 inputs such as future interest rates
and commodity prices. These market inputs are utilized in the discounted
cash flow calculation considering the instrument’s term, notional amount,
discount rate and credit risk and are classified as Level 2 in the
hierarchy. The Partnership has no financial assets and liabilities as of
September 30, 2008 valued based on inputs classified as Level 3 in the
hierarchy.
12. Subsequent
Events
Partner
Distributions. On October 24, 2008, the Partnership announced
a distribution of $0.445 per common and subordinated unit including units
equivalent to the General Partner’s two percent interest in the Partnership, and
an aggregate distribution of approximately $577,000 with respect to incentive
distribution rights, payable on November 14, 2008 to unitholders of record at
the close of business on November 7, 2008.
Item 2. Management’s 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 growth-oriented
publicly-traded Delaware limited partnership engaged in the gathering,
processing, contract compression, marketing, and transportation of natural gas
and NGLs. We provide these services through systems located in Louisiana,
Texas, Arkansas, and the mid-continent region of the United States, which
includes Kansas and Oklahoma.
RECENT
DEVELOPMENTS.
We
completed three acquisitions in the nine months ended September 30,
2008.
FrontStreet Hugoton
LLC. On January 7, 2008, the Partnership acquired all of the
outstanding equity and minority interest (the “FrontStreet Acquisition”) of
FrontStreet from ASC and EnergyOne. FrontStreet owns a gas
gathering system located in Kansas and Oklahoma, which is operated by a third
party.
The total
purchase price consisted of (a) 4,701,034 Class E common units of the
Partnership issued to ASC in exchange for its 95 percent interest and (b)
$11,752,000 in cash to EnergyOne in exchange for its five percent minority
interest and the termination of a management services contract valued at
$3,888,000. The Partnership financed the cash portion of the purchase
price with borrowings under its revolving credit facility.
In
connection with the FrontStreet Acquisition, the Partnership amended the
Partnership Agreement to create the Class E common units. The Class E
common units have the same terms and conditions as the Partnership’s common
units, except that the Class E common units are not entitled to participate in
earnings or distributions of operating surplus by the
Partnership. The Class E common units were issued in a private
placement conducted in accordance with the exemption from the registration
requirements of the Securities Act of 1933 as afforded by Section 4(2)
thereof. The Class E common units converted into common units on a
one-for-one basis on May 5, 2008.
Because
the acquisition of ASC’s 95 percent interest is a transaction between commonly
controlled entities (i.e., the buyer and the seller were each affiliates of
GECC), the Partnership accounted for this portion of the acquisition in a manner
similar to the pooling of interest method. Under this method of
accounting, our financial statements reflected historical balance sheet data for
both the Partnership and FrontStreet instead of reflecting the fair market value
of FrontStreet’s assets and liabilities. Further, certain transaction
costs that would normally be capitalized were expensed. Common control
between the Partnership and FrontStreet began on June 18, 2007.
CDM Resource Management,
Ltd. On January 15, 2008, the Partnership and an indirect
wholly owned subsidiary of the Partnership (“Merger Sub”) consummated an
agreement and plan of merger (the “Merger Agreement”) with CDM Resource
Management, Ltd. CDM provides its customers with turn-key natural gas
contract compression services to maximize their natural gas and crude oil
production, throughput, and cash flow in Texas, Louisiana, and
Arkansas. The Partnership operates and manages CDM as a separate
reportable segment.
The total
purchase price paid by the Partnership for the partnership interests of CDM
consisted of (a) the issuance of an aggregate of 7,276,506 Class D common units
of the Partnership, which were valued at $219,590,000 and (b) an aggregate of
$478,445,000 in cash, $316,500,000 of which was used to retire CDM’s debt
obligations. Of the Class D common units issued, 4,197,303 Class D
common units were deposited with an escrow agent pursuant to an escrow
agreement. Such common units constitute security to the Partnership
for a period of one year after the closing with respect to any obligations under
the Merger Agreement, including obligations for breaches of representation,
warranties and covenants.
In
connection with the CDM merger, the Partnership amended the Partnership
Agreement to create the Class D common units. The Class D common
units have the same terms and conditions as the Partnership’s common units,
except that the Class D common units are not entitled to participate in
distributions of operating surplus by the Partnership. The Class D
common units automatically convert into common units on a one-for-one basis on
the close of business on the first business day after the record date for the
quarterly distribution on the common units for the quarter ending December 31,
2008. The Class D common units were issued in a private placement
conducted in accordance with the exemption from the registration requirements of
the Securities Act of 1933 under Section 4(2) thereof.
Nexus Gas Holdings, LLC. On March 25,
2008, the Partnership acquired Nexus (“Nexus Acquisition”) by merger for
$88,486,000 in cash, including customary closing adjustments. Nexus
Gas Partners LLC, the sole member of Nexus prior to the merger (“Nexus Member”),
deposited $8,500,000 in an escrow account as security to the Partnership for a
period of one year against indemnification obligations and any purchase price
adjustment. The Partnership funded the Nexus Acquisition through
borrowings under its revolving credit facility.
Upon
consummation of the Nexus Acquisition, the Partnership acquired Nexus’ rights
under a Purchase and Sale Agreement (the “Sonat Agreement”) between Nexus and
Sonat. Pursuant to the Sonat Agreement, Nexus will purchase 136 miles
of pipeline from Sonat (the “Sonat Asset Acquisition”) that could facilitate the
Nexus gathering system’s integration into the Partnership’s north Louisiana
asset base. The Sonat Asset Acquisition is subject to abandonment
approval and jurisdictional redetermination by the FERC, as well as customary
closing conditions. Upon closing of the Sonat Asset Acquisition, the
Partnership will pay Sonat $27,500,000, and, if the closing occurs on or prior
to March 1, 2010, on certain terms and conditions as provided in the Merger
Agreement, the Partnership will make an additional payment of $25,000,000 to the
Nexus Member.
RIGS FERC
Petition. On April 29, 2008, RIGS filed a petition with the
FERC seeking approval to maintain its maximum Section 311 transportation rates
for firm and interruptible services as follows: Firm Service –
reservation fee of $4.5625 per MMBtu monthly ($0.15 per MMBtu daily) and
commodity fee of $0.05 per MMBtu; Interruptible Service – transportation fee of
$0.20 per MMBtu; and Fuel Retention - up to two percent of
receipts. The rate filing was required by a FERC Letter Order issued
on September 26, 2005, which approved a settlement in which RIGS agreed to
justify its existing rates or establish new rates for Section 311 services by
May 1, 2008.
RIGS
reached a settlement with FERC Staff on the 2008 petition, and on September 23,
2008, the FERC approved the settlement. The settlement provided for
the continuation of RIGS existing maximum transportation rates and a reduction
in RIGS’ maximum fuel retention to one and a one-half percent effective May 1,
2008. The settlement permits RIGS’ maximum fuel retention rate to
increase to two percent when new compression is added to the RIGS
system. As part of the settlement, RIGS also agreed to fully
support its requested maximum fuel retention percentage in its next rate filing
and to re-justify or establish new rates for Section 311 service by May 1,
2011. The triennial rate review requirement is a standard settlement
provision in most intrastate pipeline rate proceedings for Section 311
service.
TCEQ Notice of
Enforcement. On February 15, 2008,
the TCEQ issued a NOE concerning one of the Partnership’s processing plants
located in McMullen County, Texas (the “Plant”). The NOE alleges
that, between March 9, 2006, and May 8, 2007, the Plant experienced 15 emission
events of various durations from four hours to 41 days, which were not reported
to TCEQ and other agencies within 24 hours of occurrence. On April 3,
2008, TCEQ presented the Partnership with a written offer to settle the
allegation in the NOE in exchange for payment of an administrative penalty of
$480,000. The Partnership was unable to settle this matter on a
satisfactory basis and the TCEQ has referred the matter for further
proceedings.
Equity
Offering. On August 1, 2008, the Partnership issued 9,020,909
common units and received $204,133,000 in proceeds, inclusive of the General
Partner’s proportionate capital contribution. The net proceeds were
used to repay indebtedness under the Partnership’s revolving credit
facility. The common units were issued under the Partnership’s
universal shelf registration statement. An affiliate of GECC
purchased 2,272,727 of these common units. As of September 30, 2008,
the Partnership has incurred $34,000 in costs related to this equity
offering.
Haynesville Expansion
Project. The Haynesville Shale, located generally in northwest
Louisiana, has become one of the most active new natural gas plays in the United
States. We believe that there is insufficient transportation capacity
in place to accommodate the level of production expected in the Haynesville
Shale and that significant investment in new infrastructure is
required.
On
September 9, 2008, we announced our plans to expand RIGS to transport gas from
the Haynesville Shale to market. The Haynesville Expansion Project
was expected to add 204 miles of pipeline ranging in diameter from 24 to 42
inches and 49,000 horsepower of compression. We anticipated
completing the project in two phases. The first phase of the project
was to be completed in the first half of 2009 and would have added approximately
300 MMcf/d of capacity by constructing additional pipeline loops and adding
compression to the existing RIGS system. The second phase of the
project was to be completed in the first quarter of 2010 and would have added an
incremental 1.15 Bcf/d. The total cost was expected to be
approximately $1.1 billion, with phase one comprising approximately $375,000,000
of the total cost.
In light
of the recent
turmoil in the economic environment, we have scaled back our plans to expand
RIGS to transport gas from the Haynesville Shale to market. The
Haynesville Expansion Project is now expected to add 128 miles of pipeline
ranging in diameter from 36 to 42 inches and 12,500 horsepower of
compression. We anticipate completing the project in one phase by
December 31, 2009. This project is expected to add approximately 1.1
Bcf/d of capacity. The total cost is expected to be $650,000,000,
exclusive of capitalized interest and labor. Our ability to construct
this project is subject to our obtaining financing and entering into agreements
with shippers. See “Liquidity and Capital Resources” and “Risk
Factors” for discussion of the RIGS expansion financing.
See
“Liquidity and Capital Resources” and “Risk Factors” for discussion on the
recent credit market disruption and decreases in commodity prices.
OUR OPERATIONS. We
manage our business and analyze and report our results of operations through
three business segments.
·
|
Gathering and
Processing: We provide “wellhead-to-market” services to
producers of natural gas, which include transporting raw natural gas from
the wellhead through gathering systems, processing raw natural gas to
separate NGLs from the raw natural gas and selling or delivering the
pipeline-quality natural gas and NGLs to various markets and pipeline
systems;
|
·
|
Transportation: We
deliver natural gas from northwest Louisiana to more favorable markets in
northeast Louisiana through our 320-mile Regency Intrastate Pipeline
system; and
|
·
|
Contract
Compression: We provide customers with turn-key natural
gas compression services to maximize their natural gas and crude oil
production, throughput, and cash flow. Our integrated solutions
include a comprehensive assessment of a customer’s natural gas contract
compression needs and the design and installation of a compression system
that addresses those particular needs. We are responsible for
the installation and ongoing operation, service, and repair of our
compression units, which we modify as necessary to adapt to our customers’
changing operating conditions.
|
HOW WE EVALUATE OUR
OPERATIONS. Our management uses a variety of financial and
operational measurements to analyze our performance. We view these
key performance indicators as important tools for evaluating the success of our
operations and review these key performance indicators on a monthly basis for
consistency and trends. For our gathering and processing and
transportation segments, the key performance indicators include volumes, segment
margin, and operating and maintenance expenses. For our contract
compression segment, the key performance indicators include revenue generating
horsepower, average horsepower per revenue generating compression unit, segment
margin, and operation and maintenance expenses. Management also
reviews EBITDA for each reportable segment and in total to analyze
performance.
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 (a) the level of workovers or recompletions of existing connected
wells and successful drilling activity in areas currently dedicated to our
pipelines, (b) our ability to compete for volumes from successful new wells in
other areas and (c) our ability to obtain natural gas that has been released
from other commitments. We routinely monitor producer activities 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.
Revenue Generating
Horsepower. Revenue generating horsepower growth is the
primary driver for revenue growth in the contract compression segment, and it is
also the base measure for evaluating our operational
efficiency. Revenue generating horsepower is our total available
horsepower less horsepower under contract that is not generating revenue and
idle horsepower.
Average Horsepower per Revenue
Generating Compression
Unit. We calculate average horsepower per revenue generating
compression unit as our revenue generating horsepower divided by the number of
revenue generating compression units.
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.
We
calculate our contract compression segment margin as our revenues generated from
our contract compression operations minus the direct costs, primarily compressor
unit repairs, associated with those revenues.
Total Segment
Margin. Segment margin from gathering and processing,
transportation, contract compression and inter-segment eliminations comprise
total segment margin. We use total segment margin as a measure of
performance. The reconciliation of the non-GAAP financial measure,
total segment margin, to its most directly comparable GAAP measure, net income
(loss), is included in Note 9, Segment Information, within the condensed
consolidated financial statements included in Item 1 of this
report.
Operation and Maintenance
Expenses. 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 flowing 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 measures, net loss and net
cash flows provided by operating activities.
|
|
Nine
Months Ended
|
|
|
|
September
30, 2008
|
|
|
September
30, 2007
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
Net
cash flows provided by operating activities
|
|
$ |
149,280 |
|
|
$ |
49,181 |
|
Add
(deduct):
|
|
|
|
|
|
|
|
|
Depreciation
and amortization, including debt issuance cost
amortization
|
|
|
(76,751 |
) |
|
|
(40,627 |
) |
Write-off
of debt issuance costs
|
|
|
- |
|
|
|
(5,078 |
) |
Equity
income and minority interest in earnings
|
|
|
(165 |
) |
|
|
(130 |
) |
Risk
management portfolio valuation changes
|
|
|
1,007 |
|
|
|
(1,634 |
) |
Loss
on asset sales
|
|
|
(434 |
) |
|
|
(1,562 |
) |
Unit
based compensation expenses
|
|
|
(3,087 |
) |
|
|
(14,790 |
) |
Gain
on insurance settlements
|
|
|
3,282 |
|
|
|
- |
|
Changes
in current assets and liabilities:
|
|
|
|
|
|
|
|
|
Trade
accounts receivables and accrued revenues
|
|
|
11,084 |
|
|
|
14,857 |
|
Other
current assets
|
|
|
(38 |
) |
|
|
(251 |
) |
Trade
accounts payable, accrued cost of gas and liquids, and related party
payables
|
|
|
11,125 |
|
|
|
(15,171 |
) |
Other
current liabilities
|
|
|
(22,448 |
) |
|
|
(4,132 |
) |
Other
assets and liabilities
|
|
|
(3,628 |
) |
|
|
946 |
|
Net
income (loss)
|
|
$ |
69,227 |
|
|
$ |
(18,391 |
) |
Add:
|
|
|
|
|
|
|
|
|
Interest
expense, net
|
|
|
48,261 |
|
|
|
41,740 |
|
Depreciation
and amortization
|
|
|
74,638 |
|
|
|
39,123 |
|
Income
tax expense
|
|
|
142 |
|
|
|
65 |
|
EBITDA
|
|
$ |
192,268 |
|
|
$ |
62,537 |
|
CASH
DISTRIBUTIONS. On October 24, 2008, the Partnership announced
a distribution of $0.445 per common and subordinated unit including units
equivalent to the General Partner’s two percent interest in the Partnership, and
an aggregate distribution of approximately $577,000 with respect to incentive
distribution rights, payable on November 14, 2008 to unitholders of record at
the close of business on November 7, 2008.
RESULTS
OF OPERATIONS
Three
Months Ended September 30, 2008 vs. Three Months Ended September 30,
2007
The
following table contains key company-wide performance indicators related to our
discussion of the results of operations.
|
|
Three
Months Ended
|
|
|
|
|
|
|
|
|
|
September
30, 2008
|
|
|
September
30, 2007
|
|
|
Change
|
|
|
Percent
|
|
|
|
(in
thousands except percentages and volume data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
547,175 |
|
|
$ |
295,824 |
|
|
$ |
251,351 |
|
|
|
85
|
% |
Cost
of sales
|
|
|
408,165 |
|
|
|
234,946 |
|
|
|
173,219 |
|
|
|
74 |
|
Total
segment margin (1)
|
|
|
139,010 |
|
|
|
60,878 |
|
|
|
78,132 |
|
|
|
128 |
|
Operation
and maintenance
|
|
|
33,688 |
|
|
|
18,134 |
|
|
|
15,554 |
|
|
|
86 |
|
General
and administrative
|
|
|
13,976 |
|
|
|
6,983 |
|
|
|
6,993 |
|
|
|
100 |
|
Loss
on asset sales, net
|
|
|
(34 |
) |
|
|
(777 |
) |
|
|
743 |
|
|
|
96 |
|
Transaction
expenses
|
|
|
2 |
|
|
|
- |
|
|
|
2 |
|
|
|
N/M |
|
Depreciation
and amortization
|
|
|
26,422 |
|
|
|
14,993 |
|
|
|
11,429 |
|
|
|
76 |
|
Operating
income
|
|
|
64,956 |
|
|
|
21,545 |
|
|
|
43,411 |
|
|
|
201 |
|
Interest
expense, net
|
|
|
(16,072 |
) |
|
|
(10,894 |
) |
|
|
(5,178 |
) |
|
|
48 |
|
Loss
on debt refinancing
|
|
|
- |
|
|
|
(21,200 |
) |
|
|
21,200 |
|
|
|
100 |
|
Other
income and deductions, net
|
|
|
118 |
|
|
|
713 |
|
|
|
(595 |
) |
|
|
83 |
|
Minority
interest
|
|
|
(162 |
) |
|
|
(156 |
) |
|
|
(6 |
) |
|
|
4 |
|
Income
tax benefit
|
|
|
(67 |
) |
|
|
(160 |
) |
|
|
93 |
|
|
|
58 |
|
Net
income (loss)
|
|
$ |
48,907 |
|
|
$ |
(9,832 |
) |
|
$ |
58,739 |
|
|
|
597
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
System
inlet volumes (MMbtu/d) (2)
|
|
|
1,604,655 |
|
|
|
1,377,453 |
|
|
|
227,202 |
|
|
|
16 |
|
Revenue
generating horsepower (3)
|
|
|
742,804 |
|
|
|
- |
|
|
|
N/A |
|
|
|
N/A |
|
(1) For a
reconciliation of total segment margin to its most directly comparable financial
measure calculated and presented in accordance with GAAP, please read “Item 1.
Financial Statements – Note 9, Segment Information.”
(2)
System inlet volumes include total volumes taken into both our gathering and
processing and transportation systems.
(3)
Revenue generating horsepower is our total available horsepower less horsepower
under contract that is not generating revenue and idle horsepower.
N/M – not
meaningful.
N/A – not
applicable as we acquired the business in January 2008.
The table
below contains key segment performance indicators related to our discussion of
the results of operations.
|
|
Three
Months Ended
|
|
|
|
|
|
|
|
|
|
September
30, 2008
|
|
|
September
30, 2007
|
|
|
Change
|
|
|
Percent
|
|
|
|
(in
thousands except percentage and volume data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
Financial and Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering
and Processing Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin
|
|
$ |
86,642 |
|
|
$ |
45,590 |
|
|
$ |
41,052 |
|
|
|
90
|
% |
Operation
and maintenance
|
|
|
25,218 |
|
|
|
16,688 |
|
|
|
8,530 |
|
|
|
51 |
|
Operating
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(MMbtu/d) (1)
|
|
|
1,082,139 |
|
|
|
882,008 |
|
|
|
200,131 |
|
|
|
23 |
|
NGL
gross production (Bbls/d)
|
|
|
21,386 |
|
|
|
22,655 |
|
|
|
(1,269 |
) |
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin
|
|
$ |
19,718 |
|
|
$ |
15,288 |
|
|
$ |
4,430 |
|
|
|
29 |
|
Operation
and maintenance
|
|
|
(927 |
) |
|
|
1,446 |
|
|
|
(2,373 |
) |
|
|
164 |
|
Operating
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(MMbtu/d) (1)
|
|
|
795,104 |
|
|
|
788,789 |
|
|
|
6,315 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
Compression Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin
|
|
$ |
32,650 |
|
|
$ |
- |
|
|
|
N/A |
|
|
|
N/A |
|
Operation
and maintenance
|
|
|
9,397 |
|
|
|
- |
|
|
|
N/A |
|
|
|
N/A |
|
(1)
Combined throughput volumes for the gathering and processing and transportation
segments vary from consolidated system inlet volumes due to inter-segment
eliminations between the two segments.
N/A – not
applicable as we acquired the business in January 2008.
The
tables below contain key performance indicators for the contract compression
segment.
|
|
For
the Period Ended
|
|
|
|
March
31, 2008
|
|
|
June
30, 2008
|
|
|
September
30, 2008
|
|
Revenue
generating horsepower
|
|
|
615,852 |
|
|
|
669,804 |
|
|
|
742,804 |
|
Revenue
generating units
|
|
|
725 |
|
|
|
789 |
|
|
|
873 |
|
Average
horsepower
|
|
|
849 |
|
|
|
849 |
|
|
|
851 |
|
In
addition to the revenue generating horsepower and units owned and operated by
the contract compression segment disclosed in the above table, the contract
compression segment operates 186,601 horsepower owned by the gathering and
processing and transportation segments.
|
|
|
For
the Period Ended September
30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Horsepower
Range
|
|
|
Revenue
Generating Horsepower |
|
|
Percentage
of Revenue Generating Horsepower
|
|
|
|
|
|
0-499 |
|
|
|
56,178 |
|
|
|
8 |
% |
|
|
337 |
|
|
500-999 |
|
|
|
82,016 |
|
|
|
11 |
% |
|
|
132 |
|
|
1,000 |
+ |
|
|
604,610 |
|
|
|
81 |
% |
|
|
404 |
|
|
|
|
|
|
742,804 |
|
|
|
100 |
% |
|
|
873 |
|
Net Income. Net
income for the three months ended September 30, 2008 was $48,907,000 compared to
net loss of $9,832,000 for the three months ended September 30, 2007, a
$58,739,000 increase. The increase in net income was primarily due to an
increase in total segment margin of $78,132,000 and the absence in the current
period of $21,200,000 loss on debt refinancing for the early termination penalty
associated with the redemption of 35 percent of our senior notes incurred during
the three months ended September 30, 2007, partially offset
by:
·
|
an
increase in operation and maintenance expense of $15,554,000 primarily due
to operation and maintenance expenses in the contract compression segment
assets that were acquired in January 2008 and an increase in
employee-related expenses mainly in the gathering and processing
segment;
|
·
|
an
increase in depreciation and amortization expense of $11,429,000 primarily
due to our CDM, FrontStreet and Nexus acquisitions and organic growth
projects;
|
·
|
an
increase in general and administrative expenses of $6,993,000 primarily
due to our contract compression assets acquired in January 2008 and
increased employee-related expenses; and
|
·
|
an
increase in interest expense of $5,178,000 primarily due to increased
levels of borrowings.
|
Segment
Margin. Total segment margin for the three months ended
September 30, 2008 increased $78,132,000 compared with the three months ended
September 30, 2007. This increase was attributable to an increase of
$41,052,000 in gathering and processing segment margin, an increase of
$4,430,000 in transportation segment margin and the addition of $32,650,000 in
contract compression segment margin in the three months ended September 30,
2008, as further discussed below.
Gathering
and processing segment margin increased to
$86,642,000 for the three months ended September 30, 2008 from $45,590,000 for
the three months ended September 30, 2007. The major components of
this increase were as follows:
·
|
$24,581,000
from non-cash changes in the value of certain risk management contracts
related to our hedging programs;
|
·
|
$7,105,000
from increased throughput volumes in north Louisiana;
|
·
|
$5,185,000
from increased sulphur prices;
|
·
|
$3,610,000
from organic growth projects placed into service in south Texas that did
not exist in the prior period;
|
·
|
$2,582,000
from the operations of our Nexus assets; and were partially offset
by
|
·
|
$2,011,000
decrease from various other
sources.
|
Transportation
segment margin increased to $19,718,000 for the three months ended September 30,
2008 from $15,288,000 for the three months ended September 30,
2007. The major components of this increase were as
follows:
·
|
$1,992,000
in increased margins associated with our limited marketing
function;
|
·
|
$1,482,000
from increased operational efficiencies coupled with increased commodity
prices; and
|
·
|
$993,000
from increased throughput volumes and changes to contract
mix.
|
Contract
compression segment margin was $32,650,000 in the three months ended September
30, 2008 which consisted of $36,073,000 of operating revenues and
$3,423,000 of direct operating costs.
Operation and
Maintenance. Operation and maintenance expense increased to
$33,688,000 in the three months ended September 30, 2008 from $18,134,000 for
the corresponding period in 2007, an 86 percent increase. This
increase is primarily the result of the following factors:
·
|
$9,397,000
related to our contract compression business acquired in January
2008;
|
·
|
$6,553,000
related to the gathering and processing segment associated primarily with
an increased amount of assets due to organic growth projects since
September 30, 2007 and increased compressor and other maintenance expenses
in 2008;
|
·
|
$983,000
increase in gathering and processing segment employee-related expenses
primarily related to increased bonus accruals and employer benefit
payments;
|
·
|
$631,000
increase in contractor expense in the transportation segment due to
compressor maintenance;
|
·
|
$536,000
related to our FrontStreet assets, which is operated by a third
party;
|
·
|
$267,000
increase in utility expense due to higher costs; and were partially offset
by
|
·
|
$3,134,000
in insurance proceeds received in the three months ended September 30,
2008 related to a compressor fire on the RIGS
system.
|
General and
Administrative. General and administrative expense increased
to $13,976,000 in the three months ended September 30, 2008 from $6,983,000 for
the same period in 2007, a 100 percent increase. This increase is
primarily due to:
·
|
$4,427,000
related to our contract compression assets acquired January 2008;
and
|
·
|
$2,185,000
increase in employee-related expenses primarily due to increased employer
benefit payments and bonus
accruals.
|
Depreciation and
Amortization. Depreciation and amortization expense increased
to $26,422,000 in the three months ended September 30, 2008 from $14,993,000 for
the three months ended September 30, 2007, a 76 percent
increase. The following factors contributed to this
increase:
·
|
$7,537,000
related to our contract compression business acquired in January
2008;
|
·
|
$1,490,000
related to our FrontStreet assets which are now depreciated over a shorter
useful life as compared to 2007;
|
·
|
$1,386,000
related to various organic growth projects completed since September 30,
2007, primarily in the gathering and processing segment;
and
|
·
|
$1,016,000
related to our Nexus acquisition in March
2008.
|
Interest Expense,
Net. Interest expense, net increased by $5,178,000, or 48
percent, in the three months ended September 30, 2008 compared to the same
period in 2007. Interest expense, net increased by $7,228,000 due to
increased levels of borrowings, partially offset by a decrease of $3,941,000
primarily attributable to lower interest rates and $1,891,000 related to a
decrease in capitalized interest and a realized gain on a swap settlement in the
three months ended September 30, 2007.
Nine
Months Ended September 30, 2008 vs. Nine Months Ended September 30,
2007
The
following table contains key company-wide performance indicators related to our
discussion of the results of operations.
|
|
Nine
Month Ended
|
|
|
|
|
|
|
|
|
|
September
30, 2008
|
|
|
September
30, 2007
|
|
|
Change
|
|
|
Percent
|
|
|
|
(in
thousands except percentages and volume data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
1,499,115 |
|
|
$ |
855,081 |
|
|
$ |
644,034 |
|
|
|
75
|
% |
Cost
of sales
|
|
|
1,168,441 |
|
|
|
696,644 |
|
|
|
471,797 |
|
|
|
68 |
|
Total
segment margin (1)
|
|
|
330,674 |
|
|
|
158,437 |
|
|
|
172,237 |
|
|
|
109 |
|
Operation
and maintenance
|
|
|
95,049 |
|
|
|
41,031 |
|
|
|
54,018 |
|
|
|
132 |
|
General
and administrative
|
|
|
38,784 |
|
|
|
32,928 |
|
|
|
5,856 |
|
|
|
18 |
|
Loss
on asset sales, net
|
|
|
434 |
|
|
|
1,562 |
|
|
|
(1,128 |
) |
|
|
72 |
|
Management
service termination fee
|
|
|
3,888 |
|
|
|
- |
|
|
|
3,888 |
|
|
NM
|
|
Transaction
expenses
|
|
|
536 |
|
|
|
- |
|
|
|
536 |
|
|
NM
|
|
Depreciation
and amortization
|
|
|
74,638 |
|
|
|
39,123 |
|
|
|
35,515 |
|
|
|
91 |
|
Operating
income
|
|
|
117,345 |
|
|
|
43,793 |
|
|
|
73,552 |
|
|
|
168 |
|
Interest
expense, net
|
|
|
(48,261 |
) |
|
|
(41,740 |
) |
|
|
(6,521 |
) |
|
|
16 |
|
Loss
on debt refinancing
|
|
|
- |
|
|
|
(21,200 |
) |
|
|
21,200 |
|
|
|
100 |
|
Other
income and deductions, net
|
|
|
450 |
|
|
|
951 |
|
|
|
(501 |
) |
|
|
53 |
|
Minority
interest
|
|
|
(165 |
) |
|
|
(130 |
) |
|
|
(35 |
) |
|
|
27 |
|
Income
tax expense
|
|
|
142 |
|
|
|
65 |
|
|
|
77 |
|
|
|
118 |
|
Net
income (loss)
|
|
$ |
69,227 |
|
|
$ |
(18,391 |
) |
|
$ |
87,618 |
|
|
|
476
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
System
inlet volumes (MMbtu/d) (2)
|
|
|
1,500,714 |
|
|
|
1,248,773 |
|
|
|
251,942 |
|
|
|
20 |
|
Revenue
generating horsepower (3)
|
|
|
742,804 |
|
|
|
- |
|
|
|
N/A |
|
|
|
N/A |
|
(1) For a
reconciliation of total segment margin to its most directly comparable financial
measure calculated and presented in accordance with GAAP, please read “Item 1.
Financial Statements – Note 9, Segment Information.”
(2)
System inlet volumes include total volumes taken into both our gathering and
processing and transportation systems.
(3)
Revenue generating horsepower is our total available horsepower less horsepower
under contract that is not generating revenue and idle horsepower.
N/M – not
meaningful.
N/A – not
applicable as we acquired the business in January 2008.
The table
below contains key segment performance indicators related to our discussion of
the results of operations.
|
|
Nine
Month Ended
|
|
|
|
|
|
|
|
|
|
September
30, 2008
|
|
|
September
30, 2007
|
|
|
Change
|
|
|
Percent
|
|
|
|
(in
thousands except percentages and volume data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
Financial and Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering
and Processing Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin
|
|
$ |
187,138 |
|
|
$ |
115,467 |
|
|
$ |
71,671 |
|
|
|
62
|
% |
Operation
and maintenance
|
|
|
63,656 |
|
|
|
36,285 |
|
|
|
27,371 |
|
|
|
75 |
|
Operating
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(MMbtu/d) (1)
|
|
|
998,518 |
|
|
|
794,173 |
|
|
|
204,345 |
|
|
|
26 |
|
NGL
gross production (Bbls/d)
|
|
|
22,323 |
|
|
|
21,233 |
|
|
|
1,090 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin
|
|
$ |
58,215 |
|
|
$ |
42,970 |
|
|
$ |
15,245 |
|
|
|
35 |
|
Operation
and maintenance
|
|
|
1,931 |
|
|
|
4,746 |
|
|
|
(2,815 |
) |
|
|
59 |
|
Operating
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(MMbtu/d) (1)
|
|
|
773,562 |
|
|
|
757,367 |
|
|
|
16,195 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
Compression Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment
margin
|
|
$ |
85,321 |
|
|
$ |
- |
|
|
|
N/A |
|
|
|
N/A |
|
Operation
and maintenance
|
|
|
29,462 |
|
|
|
- |
|
|
|
N/A |
|
|
|
N/A |
|
(1)
Combined throughput volumes for the gathering and processing and transportation
segment vary from consolidated system inlet volumes due to inter-segment
eliminations between the two segments.
N/A – not
applicable as we acquired the business in January 2008.
Net Income. Net
income for the nine months ended September 30, 2008 was $69,227,000 compared to
net loss of $18,391,000 for the nine months ended September 30, 2007, a 476
percent increase. The increase in net income was primarily due to an
increase in total segment margin of $172,237,000 and the absence in the current
period of $21,200,000 loss on debt refinancing for the early termination penalty
associated with the redemption of 35 percent of our senior notes incurred during
the nine months ended September 30, 2007; partially offset by:
·
|
an
increase in operation and maintenance expense of $54,018,000 primarily due
to operation and maintenance expenses related to our CDM and FrontStreet
assets acquired in January 2008 and increased contractor and
employee-related expenses in the gathering and processing
segment;
|
·
|
an
increase in depreciation and amortization expense of $35,515,000 due to
our CDM, FrontStreet and Nexus acquisitions and organic growth
projects;
|
·
|
an
increase in general and administrative expense of $5,856,000, primarily
due to the CDM and FrontStreet acquisitions and higher performance bonus
accruals, reduced by the absence of a charge associated with the vesting
of all outstanding LTIP grants incurred in the nine months ended September
30, 2007 when GE EFS acquired our general partner;
|
·
|
an
increase in interest expense of $6,521,000 primarily due to increased
borrowing levels; and
|
·
|
a
payment of management contract services termination fee of $3,888,000 in
the nine months ended September 30, 2008 related to the acquisition of
FrontStreet.
|
Segment
Margin. Total segment margin for the nine months ended
September 30, 2008 increased $172,237,000 compared with the nine months ended
September 30, 2007. This increase was attributable to an increase of
$71,671,000 in gathering and processing segment margin, an increase of
$15,245,000 in transportation segment margin and the addition of $85,321,000 in
contract compression segment margin in the nine months ended September 30, 2008,
as discussed below.
Gathering
and processing segment margin increased to
$187,138,000 for the nine months ended September 30, 2008 from $115,467,000 for
the nine months ended September 30, 2007. The major components of
this increase were as follows:
·
|
$22,352,000
from the operations of FrontStreet assets which were acquired in January
2008, but accounted for in a manner similar to a pooling of interests from
June 18, 2007. Thus, the results of the FrontStreet assets are
only present for three and one-half months during the nine months ended
September 30, 2007;
|
·
|
$16,462,000
from organic growth projects placed into service in south Texas that did
not exist in the prior period;
|
·
|
$11,112,000
from increased throughput volumes in north Louisiana;
|
·
|
$8,722,000
from increased sulfur prices;
|
·
|
$5,373,000
from the operation of the Nexus assets acquired in March 2008;
and
|
·
|
$4,317,000
increase from non-cash changes in the value of certain risk management
contracts.
|
Transportation
segment margin increased to $58,215,000 for the nine months ended September 30,
2008 from $42,970,000 for the nine months ended September 30,
2007. The major components of this increase were as
follows:
·
|
$10,132,000
from increased operational efficiencies coupled with increased commodity
prices;
|
·
|
$3,665,000
from increased margins associated with our limited marketing
function;
|
·
|
$2,144,000
from increased throughput volumes and changes to contract mix;
and
|
·
|
$695,000
decrease from non cash changes in the value of certain risk management
contracts.
|
Contract
compression segment margin was $85,321,000 in the nine months ended September
30, 2008, which consisted of $94,016,000 of operating revenue and
$8,695,000 of direct operating costs.
Operation and
Maintenance. Operation and maintenance expense increased to
$95,049,000 in the nine months ended September 30, 2008 from $41,031,000 for the
corresponding period in 2007, a 132 percent increase. This increase
is primarily the result of the following factors:
·
|
$29,462,000 related
to our contract compression business acquired in January
2008;
|
·
|
$12,562,000
related to our FrontStreet assets, primarily contractor expense in the
nine months ended September 30, 2008 compared to three and half month’s
operations in 2007;
|
·
|
$8,669,000
related to the gathering and processing segment associated primarily with
an increased amount of assets due to organic growth projects since
September 30, 2007 and increased compressor and other maintenance expenses
in 2008;
|
·
|
$3,577,000
increase in employee expenses primarily in the gathering and processing
segment primarily related to increased employer benefit payments and bonus
payments and accruals;
|
·
|
$975,000
increase in utility expenses primarily in the gathering and processing
segment due to higher electricity costs;
|
·
|
$931,000
increase in property taxes related to our FrontStreet assets in the nine
month ended September 30, 2008 versus three and half month in
2007;
|
·
|
$976,000
increase in various other operation and maintenance expenses; and were
partially offset by
|
·
|
$3,134,000
in insurance proceeds received in August 2008 related to a 2007 compressor
fire on the RIGS system in the transportation
segment.
|
General and
Administrative. General and administrative expense increased
to $38,784,000 in the nine months ended September 30, 2008 from $32,928,000 for
the same period in 2007, an 18 percent increase. In June 2007, the
Partnership incurred a one-time charge of $11,928,000 associated with the
vesting of all outstanding common unit options and restricted unit options upon
a change in control, when GE EFS acquired our general partner. Absent
this charge, general and administrative expenses increase by $17,784,000
primarily due to:
·
|
$11,499,000
related to our contract compression business acquired in January 2008;
and
|
·
|
$5,743,000
increase in employee related expenses primarily due to increased bonus
accruals and employer benefit
payments.
|
Management Services Termination
Fee. In the nine months ended September 30, 2008, we recorded
a charge of $3,888,000 for the termination of a long-term management services
contract associated with our FrontStreet acquisition.
Depreciation and
Amortization. Depreciation and amortization expense increased
to $74,638,000 in the nine months ended September 30, 2008 from $39,123,000 for
the nine months ended September 30, 2007, a 91 percent increase. The
increase in depreciation and amortization expense is due to the following
factors:
·
|
$20,370,000
related to our contract compression assets acquired January
2008;
|
·
|
$7,176,000
related to our FrontStreet assets which are now depreciated over a shorter
useful life as compared to 2007;
|
·
|
$5,954,000
related to various organic projects completed since the June 2007,
primarily in the gathering and processing segment; and
|
·
|
$2,015,000
related to our Nexus acquisition in March
2008.
|
Interest Expense,
Net. Interest expense, net increased $6,521,000, or
16 percent, in the nine months ended September 30, 2008 compared to the
same period in 2007. Interest expense, net increased by $17,080,000
due to increased levels of borrowings, and $1,455,000 due to a decrease in
capitalized interest versus the comparison period and a realized gain on a swap
settlement in the nine months ended September 30, 2007 and decreased by
$12,014,000 due to lower interest rates.
CRITICAL ACCOUNTING POLICIES AND
ESTIMATES. In addition to the information set forth in this
report, further information regarding the Partnership’s critical accounting
policies and estimates is included in Item 7 of the Partnership’s Annual Report
on Form 10-K for the year ended December 31, 2007.
As-if Pooling of Interest Method of
Accounting. We account for acquisitions where common control
exists by following the as-if pooling method of accounting as described in SFAS
No. 141, “Business Combinations.” Under this method of accounting, we
reflect the historical balance sheet data for both the acquirer and acquiree
instead of reflecting the fair market value of acquiree’s assets and
liabilities. In common control acquisitions where a minority interest
is also acquired, we use the purchase method of accounting for the minority
interest. Further, certain transaction costs that would normally
be capitalized are expensed.
Fair Value
Measurements. On January 1, 2008, we adopted the provisions of
SFAS No. 157 for financial assets and liabilities. SFAS No. 157
defines fair value, thereby eliminating inconsistencies in guidance found in
various prior accounting pronouncements, and increases disclosures surrounding
fair value calculations. The adoption of SFAS No. 157 for financial
assets and liabilities did not have a material impact on our
financial position or cash flows for the three months ended September 30,
2008.
SFAS No.
157 establishes a three-tiered fair value hierarchy that prioritizes inputs to
valuation techniques used in fair value calculations. The three
levels of inputs are defined as follows:
·
|
Level
1 — unadjusted quoted prices for identical assets or liabilities in active
markets accessible by us;
|
·
|
Level
2 — inputs that are observable in the marketplace other than those inputs
classified as Level 1; and
|
·
|
Level
3 — inputs that are unobservable in the marketplace and significant to the
valuation.
|
SFAS No.
157 encourages us to maximize the use of observable inputs and minimize the
use of unobservable inputs. If a financial instrument valuation uses
inputs that fall in different levels of the hierarchy, the instrument will be
categorized based upon the lowest level of input that is significant to the fair
value calculation. Our financial assets and liabilities measured at
fair value on a recurring basis are derivative financial instruments consisting
of interest rate swaps and commodity swaps.
The
Partnership’s financial assets and liabilities measured at fair value on a
recurring basis are risk management assets and liabilities related to interest
rate and commodity swaps. Risk management assets and liabilities are
valued using discounted cash flow techniques. These techniques
incorporate Level 1 and Level 2 inputs such as future interest rates and
commodity prices. These market inputs are utilized in the discounted
cash flow calculation considering the instrument’s term, notional amount,
discount rate and credit risk and are classified as Level 2 in the
hierarchy. The Partnership has no financial assets and liabilities as
of September 30, 2008 valued based on inputs classified as Level 3 in the
hierarchy.
OTHER
MATTERS.
Information
regarding the Partnership’s commitments and contingencies are included in Note
7-Commitments and Contingencies to the condensed consolidated financial
statements included in Item 1 of this report.
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 have
experienced, and expect to continue to experience, substantial capital
expenditure and working capital needs, particularly as a result of our
Haynesville Expansion Project. At September 30, 2008, the Partnership
has purchase obligations totaling $428,454,000, of which $148,924,000 is
related to the purchase of major compression components unrelated to
the Haynesville Expansion Project, that extend until the year ending
December 31, 2010 and $279,530,000 of which is related to the Haynesville
Expansion Project that extend until the year ending December 31, 2009. Some
of these commitments have cancellation provisions. We are in
discussions with suppliers and vendors to reduce these
commitments. Our planned capital expenditures for 2008 and 2009 are
expected to exceed substantially the net cash generated by our
operations. In addition to using borrowings under our revolving
credit facility, in order to finance these planned capital expenditures, we will
also need to raise additional financing from future equity or debt offerings to
fund all of our budgeted capital expenditures for 2009.
Global
financial markets and economic conditions have been, and continue to be,
disrupted and volatile. The debt and equity capital markets have been
exceedingly distressed. These issues, along with significant
write-offs in the financial services sector, the re-pricing of credit risk and
the current weak economic conditions have made, and will likely continue to
make, it difficult to obtain funding. The cost of raising money in the debt and
equity capital markets has increased substantially while the availability of
funds from those markets generally has diminished significantly. We
expect that our ability to issue debt and equity at prices that are similar to
offerings in recent years will be limited over the next three to six months and
possibly longer should capital markets remain constrained. Our planned internal
growth projects continue to require us to bear the cost of constructing these
new assets before we begin to realize a return on them. As a result, we will
continue to be opportunistic in our approach to funding the remaining
expenditures from additional issuances of our equity and long-term
debt.
Also, as
a result of concerns about the stability of financial markets generally and the
solvency of counterparties specifically, the cost of obtaining money from the
credit markets generally has increased as many lenders and institutional
investors have increased interest rates, enacted tighter lending standards,
refused to refinance existing debt at maturity at all or on terms similar to our
current debt and reduced and, in some cases, ceased to provide funding to
borrowers. For example, as a result of Lehman Brothers Holding, Inc.,
or Lehman, filing a petition under Chapter 11 of the U.S. Bankruptcy Code, a
subsidiary of Lehman that is a committed lender under our credit facility has
declined requests to honor its commitment to lend up to $35,000,000 under our
credit facility. The total amounts available to us under our credit
facility as of September 30, 2008 and October 31, 2008 were $225,614,000 and
$207,353,000, respectively, which have been reduced by the amount of
Lehman's commitment that is no longer available to us. If we repay any of
the $25,871,000 we have already borrowed from Lehman, we may not be able to
reborrow such amounts. We may be unable to utilize the full borrowing
capacity under our credit facility if other lenders are not willing to provide
additional funding to make up the portion of the credit facility commitments
that Lehman’s subsidiary has refused to fund or if any of the remaining
committed lenders are unable or unwilling to fund their respective portion of
any funding request we make under our credit facility.
Further,
although we obtained commitment letters for approximately $600,000,000 of debt
financing for our Haynesville Expansion Project, those commitment letters were
obtained prior to most of the disruption in the credit markets and were subject
to the execution of definitive loan documentation and other terms and closing
conditions. Given the recent disruption in the credit markets, we
believe we will not be able to access these commitments. We expect to
reduce our growth capital expenditures in 2009 and 2010, exclusive of
the Haynesville Expansion Project, from approximately $300,000,000 per year
to approximately $100,000,000 per year. We intend to finance all of our growth
capital in the long-term with a debt to EBITDA ratio of approximately four
times. As a result of our reduced capital expenditure plans, our need to access
the debt and equity markets will be significantly reduced.
We are
seeking alternative financing sources, which could delay the execution of our
Haynesville Expansion Project and or have an adverse affect on our financing
terms. In addition, producers in the area may decrease their activity
levels in the area due to the current deterioration in the credit markets or the
recent declines in the price for natural gas. To the extent producers
in the area are unable to execute their expected drilling programs, the return
on our investment from this project may not be as attractive as we
anticipate.
Although
we intend to move forward with our planned internal growth projects, including
our Haynesville Expansion Project, we may further revise the timing and scope of
these projects as necessary to adapt to existing economic conditions and the
benefits expected to accrue to our unitholders from our expansion activities may
be muted by substantial cost of capital increases during this
period. Any delay of the Haynesville Expansion Project could result
in our not being able to enter into contracts with the anchor shippers necessary
for us to finance and construct the project. To the extent that we do not
enter into definitive transportation agreements on satisfactory terms or to the
extent producers in the area are unable to execute their exploratory drilling
and development plans in this area, the return on our investment from this
project may not be as attractive as we anticipate as we will still incur
substantial costs for commitments we have made for materials and
services. As a result of these costs our cash flows may decrease,
which could impair our liquidity position and require us to reduce our
distributions to unitholders.
Finally,
if there is a significant lessening in demand for our services as a result of
extended declines in the actual and longer term expected price of oil and gas,
we may see a further reduction in our own capital expenditures and lesser
requirements for working capital, both of which could generate operating cash
flow and liquidity compared to the prior period and offset reduced cash
generated from operations excluding working capital changes. However, such an
environment might also increase the availability of acquisitions which would
draw on such liquidity.
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. When we incur growth capital expenditures, we experience working
capital deficits as 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 12 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 contract compression segment records
significant deferred revenues, a current liability. The deferred
revenues represent billings in advance of services performed. As the
revenues associated with the deferred revenues are earned, the liability is
reduced.
Our
working capital deficit increased by $9,063,000 from December 31, 2007 to
September 30, 2008, primarily due to:
·
|
an
increase in other current liabilities of $22,448,000 primarily resulting
from deferred revenues from our contract compression segment, increased
accrued interest associated with the timing of interest payments on our
senior notes and higher borrowing levels on our revolving credit facility,
increased property tax accruals; and
|
·
|
a
decrease in cash and cash equivalents of
$18,152,000.
|
Partially
offsetting these increases in working capital deficit were the following
factors:
·
|
an
increase in net risk management asset and liabilities of $23,346,000 due
primarily to lower commodity prices associated with our derivatives
portfolio and
|
·
|
an
increase in net accounts receivable and payable of $8,229,000 due
primarily to increased total segment margin and the timing of cash
receipts and disbursements.
|
Cash Flows from
Operations. Net cash flows provided by operating activities
increased $100,099,000, or 204 percent, for the nine months ended September 30,
2008 as compared to the nine months ended September 30, 2007. Our
cash flows from operations increased primarily due to increased segment margin
from our FrontStreet and CDM acquisitions in January 2008, our Nexus acquisition
in late March 2008, our Pueblo acquisition in April 2007 and organic growth in
our gathering and processing segment.
Cash Flows from Investing
Activities. Net cash flows used in investing activities
increased $679,922,000 in the nine months ended September 30, 2008 compared to
the nine months ended September 30, 2007. Our increase in cash flows
from investing activities was primarily attributable to the FrontStreet and CDM
Acquisitions in January 2008, the Nexus Acquisition in March 2008 and higher
growth and maintenance capital expenditures discussed in “Capital
Requirements.”
Cash Flows from Financing
Activities. Net cash flows provided by financing activities
increased $548,890,000 in the nine months ended September 30, 2008 compared to
the nine months ended September 30, 2007, primarily due to increased borrowings
under our revolving credit facility used to fund the FrontStreet, CDM and Nexus
acquisitions. Also contributing to the increase in net cash flows
provided by financing activities was the equity offering discussed
below.
Equity
Offering. On August 1, 2008 the Partnership sold 9,020,909
common units for an average price of $22.18 per unit. The Partnership
received $204,133,000 in proceeds, inclusive of the General Partner’s
proportionate capital contribution of $4,082,653. The net proceeds
were used to repay indebtedness under the Partnership’s revolving credit
facility and to fund growth capital projects. The common units were
issued under the Partnership’s universal shelf registration
statement. An affiliate of GECC purchased 2,272,727 of these common
units. As of September 30, 2008, the Partnership has incurred $34,000
in costs related to this equity offering.
Credit
Ratings. Our credit ratings as of October 31, 2008 are
provided in the table below.
|
|
Moody's
|
|
|
Standard
& Poor's
|
|
Regency
Energy Partners LP
|
|
|
|
|
|
|
Corporate
rating/total debt |
|
Ba3
|
|
|
BB-
|
|
Senior
notes
|
|
B1 |
|
|
B |
|
|
|
Negative
Outlook
|
|
|
Negative
Outlook
|
|
Capital
Requirements
We
categorize our capital expenditures as either:
·
|
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
|
·
|
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 nine months ended September 30, 2008, we incurred $231,461,000 of growth
capital expenditures related to:
·
|
$126,485,000
for the fabrication of new compression packages and ancillary assets for
our contract compression segment;
|
·
|
$102,029,000
for various projects in the gathering and processing segment, primarily in
Louisiana and Texas; and
|
·
|
$2,947,000
in our transportation segment for the Haynesville Expansion
Project.
|
Our
expected calendar year 2008 organic growth capital expenditures of
$356,211,000 includes:
·
|
$143,000,000
for additional compression in our contract compression
segment;
|
·
|
$116,264,000
for various projects in the gathering and processing segment;
and
|
·
|
$96,947,000
for the Haynesville Expansion Project in the transportation
segment.
|
Maintenance Capital
Expenditures. In the nine months ended September 30, 2008, we
incurred $12,062,000 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.
Contractual
Obligations. As of September 30, 2008, we had borrowed
$649,000,000 under our revolving credit facility primarily to finance our growth
capital expenditures and first quarter 2008 acquisitions. The
following table summarizes our total contractual cash obligations for long-term
debt and purchase obligations as of September 30, 2008. This table
excludes capital lease obligations as these amounts have not materially changed
since December 31, 2007.
|
|
Payment
Period
|
|
Contractual
Cash Obligations
|
|
Total
|
|
|
2008
|
|
|
|
2009-2010
|
|
|
|
2011-2012
|
|
|
Thereafter
|
|
|
|
(in
thousands)
|
|
Long-term
debt (including interest) (1)
|
|
$ |
1,257,303 |
|
|
$ |
22,460 |
|
|
$ |
119,797 |
|
|
$ |
727,605 |
|
|
$ |
387,441 |
|
Operating
leases
|
|
|
9,560 |
|
|
|
- |
|
|
|
1,506 |
|
|
|
1,721 |
|
|
|
6,333 |
|
Purchase
obligations
|
|
|
428,454 |
|
|
|
143,173 |
|
|
|
285,281 |
|
|
|
- |
|
|
|
- |
|
Total
(2) (3)
|
|
$ |
1,695,317 |
|
|
$ |
165,633 |
|
|
$ |
406,584 |
|
|
$ |
729,326 |
|
|
$ |
393,774 |
|
(1)
Assumes a constant LIBOR interest rate of 2.5 percent plus the applicable margin
(2.0 percent as of September 30, 2008) for our revolving credit
facility. The principal of our outstanding senior notes
($357,500,000) bears a fixed interest rate of 8 3/8 percent.
(2)
Excludes physical and financial purchases of natural gas, NGLs, and other
commodities due to the nature of both the price and volume components of such
purchases, which vary on a daily or monthly basis. Additionally, we
do not have contractual commitments for fixed price and/or fixed quantities of
any material amount.
(3)
Excludes deferred tax liabilities of $8,274,000 as the amount payable by period
can not be reliably estimated in light of future business plans for the entity
that generates the deferred tax liability.
Item 3. Quantitative and Qualitative Disclosures About
Market Risk
Commodity Price
Risk. We are a net seller of NGLs, condensate, sulfur and
natural gas. As such, our financial results are exposed to
fluctuations in commodity pricing. We have executed swap
contracts settled against crude oil, ethane, propane, normal butane, iso butane,
and natural gasoline. We have hedged our expected exposure to
declines in prices for NGLs and condensate volumes produced for our account
in the approximate percentages set forth below:
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
NGL
|
|
|
94 |
% |
|
|
88 |
% |
|
|
31 |
% |
Condensate
|
|
|
72 |
% |
|
|
70 |
% |
|
|
71 |
% |
We
continually monitor our hedging and contract portfolio and expect to continue to
adjust our hedge position as conditions warrant.
In
March 2008, the Partnership entered offsetting trades against its existing
2009 portfolio of mark-to-market hedges, which it believes will substantially
reduce the volatility of its existing 2009 hedges. This group of trades,
along with the pre-existing 2009 portfolio, will continue to be accounted for on
a mark-to-market basis. Simultaneously, the Partnership executed
additional 2009 NGL swaps which were designated under SFAS No. 133 as cash flow
hedges.
In
May 2008, the Partnership entered into one-year commodity swaps to
hedge its 2010 NGL commodity risk, except for ethane, which are accounted for
using mark-to-market accounting. We chose to delay hedging our 2010
exposure to ethane due to our perception that the prices offered by the
counterparties were sharply discounted from comparable forward crude prices.
We expect pricing to improve as the period of exposure approaches and
intend to execute hedges at such time.
The
Partnership accounts for a portion of its 2008 and all of its 2009 West Texas
Intermediate crude oil swaps using mark-to-market accounting. In August
2008, the Partnership entered into an offsetting trade against its existing 2009
West Texas Intermediate crude oil swap to minimize the volatility of the
original 2009 swap. Simultaneously, the Partnership executed an
additional 2009 West Texas Intermediate crude oil swap, which was designated
under SFAS No. 133 as a cash flow hedge. In May 2008, the Partnership
entered into a one-year West Texas Intermediate crude oil swap to hedge its 2010
condensate risk, which was designated as a cash flow hedge in June
2008.
On
February 29, 2008, the Partnership entered into two-year interest rate swaps
related to $300,000,000 of borrowings under its revolving credit facility,
effectively locking the base rate for these borrowings at 2.4 percent, plus the
applicable margin (2 percent as of September 30, 2008). These interest rate
swaps were designated as cash flow hedges on March 7, 2008.
The
following table sets forth certain information regarding our NGL, West Texas
Intermediate Crude and interest rate swaps outstanding at September 30,
2008. The relevant index price for NGL commodities that we pay is the
monthly average of the daily closing price for deliveries into Mont Belvieu,
Texas as reported by the Oil Price Information Service (OPIS).
Period
|
Underlying
|
|
Notional
Volume/Amount
|
|
We
Pay
|
|
|
We
Receive
|
|
Fair
Value Asset/(Liability)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in
thousands)
|
|
October
2008-December 2009
|
Ethane
|
|
|
888 |
|
(MBbls)
|
|
Index
|
|
|
$ |
0.58-$0.80 |
|
($/gallon)
|
|
$ |
4,198 |
|
October
2008-December 2010
|
Propane
|
|
|
816 |
|
(MBbls)
|
|
Index
|
|
|
$ |
0.93-$1.5325 |
|
($/gallon)
|
|
|
(4,311 |
) |
January
2009-December 2010
|
Iso
Butane
|
|
|
157 |
|
(MBbls)
|
|
Index
|
|
|
$ |
1.685-$1.915 |
|
($/gallon)
|
|
|
1,323 |
|
October
2008-December 2010
|
Normal
Butane
|
|
|
379 |
|
(MBbls)
|
|
Index
|
|
|
$ |
1.12-$1.895 |
|
($/gallon)
|
|
|
(2,944 |
) |
October
2008-December 2010
|
Natural
Gasoline
|
|
|
351 |
|
(MBbls)
|
|
Index
|
|
|
$ |
1.41-$2.53 |
|
($/gallon)
|
|
|
(2,801 |
) |
October
2008-December 2010
|
West
Texas Intermediate Crude
|
|
|
534 |
|
(MBbls)
|
|
Index
|
|
|
$ |
68.17-$121.30 |
|
($/Bbl)
|
|
|
(6,102 |
) |
October
2008-March 2010
|
Interest
Rate
|
|
$ |
300,000,000 |
|
|
|
2.40
% |
|
|
One-month
LIBOR |
|
|
3,275 |
|
Credit
risk adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,110 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Fair Value
|
|
$ |
(6,252 |
) |
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 General Partner, of the effectiveness of the design and operation
of our disclosure controls and procedures (as such terms are defined in Rule
13a–15(e) and 15d–15(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 September 30, 2008 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 SEC’s rules and
forms.
Internal control over financial
reporting. There have been no
changes in the Partnership’s internal controls over financial reporting that
have materially affected, or are reasonably likely to affect, the Partnership’s
internal controls over financial reporting.
Item
1. Legal Proceedings
The
information required for this item is provided in Note 7, 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.
In
addition to 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, 2007 and part II, “Item 1A.
Risk Factors” in our Quarterly Report on Form 10-Q for the three months ended
June 30, 2008 which materially affect our business, financial condition or
future results. The risks described in this report and in our Annual
Report on Form 10-K are not the only risks facing our Partnership.
Part
of our business strategy involves expanding our RIGS pipeline system in the
Haynesville Shale in North Louisiana, which is a new and emerging natural gas
play with limited drilling and production history and subject to more
uncertainties than more established formations. If producers are
unable to successfully execute their planned drilling programs in the
Haynesville Shale, our Haynesville Expansion Project may not be
successful.
The
success of our Haynesville Expansion Project is subject to successful
exploration and development of the Haynesville Shale, a new and emerging natural
gas play. The results of producers’ exploratory drilling in new or
emerging plays, such as the Haynesville Shale, are more uncertain than drilling
results in areas that are developed and have established
production. Since the Haynesville Shale has limited production
history, past drilling results in this area will not necessarily predict future
drilling results in the area. In addition, producers in the area
have decreased their activity levels in the area due to the current
deterioration in the credit markets or the recent declines in the price for
natural gas. To the extent producers in the area are unable to
execute their expected drilling programs, the return on our investment from this
project may not be as attractive as we anticipate. In addition, to
the extent we are unable to execute or complete the Haynesville Expansion
Project, because of capital constraints, or otherwise, the return on our
investment in this area may not be as attractive as we anticipate and our common
unit price may decrease.
If
we are unable to fully contract for transportation capacity on our Haynesville
Expansion Project, our business and our operating results could be adversely
affected.
If we are
unable to negotiate definitive firm transportation agreements with
producers for capacity on our Haynesville Expansion Project, we will not
construct the project and this could have an adverse affect on our business
and our operating results. Additionally, if we are unable to contract
for the remaining incremental transportation capacity, our business and our
operating results could be adversely affected.
We
may have difficulty financing our planned capital expenditures, which could
adversely affect our results and growth.
We have
experienced, and expect to continue to experience, substantial capital
expenditure and working capital needs, particularly as a result of our
Haynesville Expansion Project. At September 30, 2008, the Partnership
has purchase obligations totaling $428,454,000, of which $148,924,000 is
related to the purchase of major compression components unrelated to
the Haynesville Expansion Project, that extend until the year ending
December 31, 2010 and $279,530,000 of which is related to the
Haynesville Expansion Project that extend until the year ending December 31,
2009. Although we are in discussions with suppliers and vendors to reduce
these commitments, our capital expenditures for 2008 and 2009 are expected
to exceed substantially the net cash generated by our operations. In
addition to using borrowings under our revolving credit facility, we will need
to raise additional financing from future equity or debt offerings to fund all
of our budgeted capital expenditures for 2009.
Global
financial markets and economic conditions have been, and continue to be,
disrupted and volatile. The debt and equity capital markets have been
exceedingly distressed. These issues, along with significant
write-offs in the financial services sector, the re-pricing of credit risk and
the current weak economic conditions have made, and will likely continue to
make, it difficult to obtain funding.
The cost
of raising money in the debt and equity capital markets has increased
substantially while the availability of funds from those markets generally has
diminished significantly. Also, as a result of concerns about the
stability of financial markets generally and the solvency of counterparties
specifically, the cost of obtaining money from the credit markets generally has
increased as many lenders and institutional investors have increased interest
rates, enacted tighter lending standards, refused to refinance existing debt at
maturity at all or on terms similar to our current debt and reduced and, in some
cases, ceased to provide funding to borrowers.
In
addition, because of the recent downturn in the financial markets, including the
issues surrounding the solvency of many institutional lenders and the recent
failure of several banks, our ability to obtain capital from our credit facility
may be impaired. For example, as a result of Lehman Brothers Holding,
Inc., or Lehman, filing a petition under Chapter 11 of the U.S. Bankruptcy Code,
a subsidiary of Lehman that is a committed lender under our credit facility has
declined requests to honor its commitment to lend up to $35,000,000 under our
credit facility. To date, we have borrowed $25,871,000 from Lehman,
thereby effectively reducing the amount available to us under our credit
facility to $890,871,000. Upon the repayment of all of our existing
outstanding borrowings, the amount available to us under our credit facility
will be effectively reduced to $865,000,000. We may be unable to
utilize the full borrowing capacity under our credit facility if other lenders
are not willing to provide additional funding to make up the portion of the
credit facility commitments that Lehman’s subsidiary has refused to fund or if
any of the remaining committed lenders is unable or unwilling to fund their
respective portion of any funding request we make under our credit
facility.
Although
we obtained commitment letters for approximately $600,000,000 of debt financing
for our Haynesville Expansion Project, these commitment letters
were subject to the execution of definitive loan documentation and other
terms and closing conditions. Given the recent disruption in the credit
markets, we believe we will not be able to access these commitments. We are
seeking alternative financing sources, which could delay the execution of our
Haynesville Expansion Project and or have an adverse affect on our financing
terms. Additionally, we intend to finance the remaining costs of the
project by using available capacity under our revolving credit agreement and
with proceeds from the future issuance of equity. Given that the
expansion project will involve the addition of a significant amount of
indebtedness and the project will not be operational for an extended period of
time, we could be subject to downgrades or being placed on negative watch by the
credit rating agencies before the Haynesville Expansion Project results in
positive cash flows. Any such downgrade or negative watch could have
an adverse effect on our ability to obtain financing or increase the cost of
such financing. If we are not able to borrow sufficient amounts under our
revolving credit facility and/or are unable to raise sufficient capital to fund
our capital expenditures, we may be required to curtail our expansion
activities. Any such curtailment could have a material adverse effect
on our results and on our future operations.
We may not be able to
manage growth relating
to our Haynesville
Expansion Project
effectively, which could decrease our cash flow and adversely affect our results
of operation.
Our
ability to grow successfully through our Haynesville Expansion Project will
depend on a number of factors, some of which will be beyond our control. In
general, the construction of additions to or modifications of our existing
systems, and the construction of any other new midstream assets involve numerous
regulatory, environmental, political and legal uncertainties beyond our
control. Our Haynesville Expansion Project may not be completed at
budgeted cost, on schedule or at all. Construction may occur over an
extended period, and we are not likely to receive a material increase in
revenues related to the Haynesville Expansion Project until it is
completed. Moreover, our revenues may not increase immediately upon
its completion because the anticipated growth in gas production that the project
is intended to capture does not materialize, our estimates of the growth in
production prove inaccurate or for other reasons. For any of these
reasons, our Haynesville Expansion Project may not generate our expected
investment return and that, in turn, could adversely affect our cash flows and
results of operations.
In
addition, we will be required to obtain new rights-of-way in connection with the
Haynesville Expansion Project. We may be unable to obtain such
rights-of-way to capitalize on this project. If the cost of obtaining
new rights-of-way increases, then our cash flows from this project could be
adversely affected.
Because
of the natural decline in production from existing wells, our success depends on
our ability to obtain new supplies of natural gas, which involves factors beyond
our control. Any decrease in supplies of natural gas in our areas of
operation could adversely affect our business and operating
results.
Our
gathering and processing and transportation pipeline systems are dependent on
the level of production from natural gas wells that supply our systems and from
which production will naturally decline over time. As a result, our
cash flows associated with these wells will also decline over
time. In order to maintain or increase through-put volume levels on
our gathering and transportation pipeline systems and the asset utilization
rates at our natural gas processing plants, we must continually obtain new
supplies. The primary factors affecting our ability to obtain new
supplies of natural gas and attract new customers to our assets are: the level
of successful drilling activity near our systems and our ability to compete with
other gathering and processing companies for volumes from successful new
wells.
The level
of natural gas drilling activity is dependent on economic and business factors
beyond our control. The primary factor that impacts drilling
decisions is natural gas prices. A sustained decline in natural gas
prices could result in a decrease in exploration and development activities in
the fields served by our gathering and processing facilities and pipeline
transportation systems, which would lead to reduced utilization of these
assets. In addition, producers may decrease their activity levels due
to the current deterioration in the credit markets. The recent decline in the
credit markets and the availability of credit and the lack of availability of
debt or equity financing or the recent declines in natural gas prices may result
in a significant reduction in producers’ exploratory drilling. Other
factors that impact production decisions include producers’ capital budget
limitations, the ability of producers to obtain necessary drilling and other
governmental permits and regulatory changes. Because of these
factors, even if additional natural gas reserves were discovered in areas served
by our assets, producers may choose not to develop those reserves. If
we were not able to obtain new supplies of natural gas to replace the natural
decline in volumes from existing wells due to reductions in drilling activity or
competition, through-put volumes on our pipelines and the utilization rates of
our processing facilities would decline, which could have a material adverse
effect on our business, results of operations and financial
condition.
Our
natural gas contract compression operations significantly depend upon the
continued demand for and production of natural gas and crude
oil. Demand may be affected by, among other factors, natural gas
prices, crude oil prices, weather, demand for energy, and availability of
alternative energy sources. Any prolonged, substantial reduction in
the demand for natural gas or crude oil would, in all likelihood, depress the
level of production activity and result in a decline in the demand for our
contract compression services and products. Lower natural gas prices
or crude oil prices over the long-term could result in a decline in the
production of natural gas or crude oil, respectively, resulting in reduced
demand for our natural gas contract compression
services. Additionally, production from natural gas sources such as
longer-lived tight sands, shales and coalbeds constitute an increasing
percentage of our compression services business. Such sources are
generally less economically feasible to produce in lower natural gas price
environments, and a reduction in demand for natural gas or natural gas lift for
crude oil may cause such sources of natural gas to be uneconomic to drill and
produce, which could in turn negatively impact the demand for our
services.
Natural
gas, NGLs and other commodity prices are volatile, and a reduction in these
prices could adversely affect our cash flow and operating results.
We are
subject to risks due to frequent and often substantial fluctuations in commodity
prices. NGL prices generally fluctuate on a basis that correlates to
fluctuations in crude oil prices. In the past, the prices of natural
gas and crude oil have been extremely volatile, and we expect this volatility to
continue. Recently, oil and natural gas prices have been extremely
volatile and have declined substantially. On November 7, 2008, the
price of oil on the New York Mercantile Exchange fell to $60.35 per barrel for
December 2008 delivery, declining to a 17-month low and from a high of $147.27
per barrel in July 2008. Volatility in oil and
natural gas prices can impact our customers’ activity levels and spending for
our products and services, as well as our margins under our keep-whole and
percentage-of proceeds natural gas gathering and processing
contracts.
The
markets and prices for natural gas and NGLs depend upon factors beyond our
control. These factors include demand for oil, natural gas and NGLs,
which fluctuates with changes in market and economic conditions and other
factors, including:
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the
impact of weather on the demand for oil and natural
gas;
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the
level of domestic oil and natural gas production;
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the
availability of imported oil and natural gas;
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actions
taken by foreign oil and gas producing nations;
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the
availability of local, intrastate and interstate transportation
systems;
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the
availability and marketing of competitive fuels;
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the
impact of energy conservation efforts; and
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the
extent of governmental regulation and
taxation.
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Our
natural gas gathering and processing businesses operate under two types of
contractual arrangements that expose our cash flows to increases and decreases
in the price of natural gas and NGLs: percentage-of-proceeds and keep-whole
arrangements. Under percentage-of-proceeds arrangements, we generally
purchase natural gas from producers and retain an agreed percentage of the
proceeds (in cash or in-kind) from the sale at market prices of pipeline-quality
gas and NGLs resulting from our processing activities. Under keep-whole
arrangements, we receive the NGLs removed from the natural gas during our
processing operations as the fee for providing our services in exchange for
replacing the thermal content removed as NGLs with a like thermal content in
pipeline-quality gas or its cash equivalent.
Under
these types of arrangements our revenues and our cash flows increase or decrease
as the prices of natural gas and NGLs fluctuate. The relationship
between natural gas prices and NGL prices may also affect our
profitability. When natural gas prices are low relative to NGL
prices, it is more profitable for us to process natural gas under keep-whole
arrangements. When natural gas prices are high relative to NGL
prices, it is less profitable for us and our customers to process natural gas
both because of the higher value of natural gas and of the increased cost
(principally that of natural gas as a feedstock and a fuel) of separating the
mixed NGLs from the natural gas. As a result, we may experience
periods in which higher natural gas prices relative to NGL prices reduce our
processing margins or reduce the volume of natural gas processed at some of our
plants.
We
are exposed to the credit risks of our key customers, and any material
nonpayment or nonperformance by our key customers could adversely affect our
cash flow and results of operations.
We are
subject to risks of loss resulting from nonpayment or nonperformance by our
customers. Any material nonpayment or nonperformance by our key
customers could reduce our ability to make distributions to our
unitholders. Many of our customers finance their activities through
cash flow from operations, the incurrence of debt or the issuance of
equity. Recently, there has been a significant decline in the credit
markets and the availability of credit. Additionally, many of our
customers’ equity values have substantially declined. The combination
of reduction of cash flow resulting from declines in commodity prices, a
reduction in borrowing bases under reserve based credit facilities and the lack
of availability of debt or equity financing may result in a significant
reduction in our customers’ liquidity and ability to make payment or perform on
their obligations to us. Furthermore, some of our customers may be
highly leveraged and subject to their own operating and regulatory risks, which
increases the risk that they may default on their obligations to
us.
Increases
in interest rates could adversely impact our unit price and our ability to issue
additional equity, in order to make acquisitions, to reduce debt, or for other
purposes.
The
interest rate on our senior notes is fixed and the loans outstanding under our
credit facility bear interest at a floating rate. In addition, interest
rates on future credit facilities and debt offerings could be higher than
current levels, causing our financing costs to increase
accordingly. As with other yield-oriented securities, the market
price for our units will be affected by the level of our cash distributions and
implied distribution yield. The distribution yield is often used by
investors to compare and rank yield-oriented securities for investment
decision-making purposes. Therefore, changes in interest rates,
either positive or negative, may affect the yield requirements of investors who
invest in our units, and a rising interest rate environment could have an
adverse effect on our unit price and our ability to issue additional
equity in order to make acquisitions, to reduce debt or for other
purposes.
Item 2. Unregistered Sales of Equity Securities and Use of
Proceeds
The
information required for this item is provided in Note 1, Organization and
Summary of Significant Accounting Policies, Note 3, Acquisitions, and Note 6,
Equity Offering 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.
The
exhibits below are filed as a part of this report:
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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November
9, 2008
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/s/
Lawrence B. Connors
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Lawrence
B. Connors
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Senior
Vice President, Finance and Chief Accounting Officer (Duly Authorized
Officer)
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