UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
|
|
|
þ
|
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the quarterly period ended
March 31,
2010
|
OR
|
o
|
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
Commission file number:
001-32329
Copano Energy, L.L.C.
(Exact Name of Registrant as
Specified in Its Charter)
|
|
|
Delaware
(State or Other Jurisdiction
of
Incorporation or Organization)
|
|
51-0411678
(I.R.S. Employer
Identification No.)
|
2727 Allen Parkway, Suite 1200
Houston, Texas 77019
(Address of Principal
Executive Offices)
(713) 621-9547
(Registrants telephone
number, including area code)
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). o
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 the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the
Exchange Act. (Check one):
|
|
|
|
Large
accelerated
filer þ
|
Accelerated
filer o
|
Non-accelerated
filer o
|
Smaller
reporting
company o
|
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
There were 65,476,911 common units of Copano Energy, L.L.C.
outstanding at April 30, 2010. Copano Energy, L.L.C.s
common units trade on The NASDAQ Stock Market LLC under the
symbol CPNO.
|
|
Item 1.
|
Financial
Statements.
|
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands, except unit information)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
54,148
|
|
|
$
|
44,692
|
|
Accounts receivable, net
|
|
|
89,203
|
|
|
|
91,156
|
|
Risk management assets
|
|
|
30,334
|
|
|
|
36,615
|
|
Prepayments and other current assets
|
|
|
3,770
|
|
|
|
4,937
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
177,455
|
|
|
|
177,400
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
850,444
|
|
|
|
841,323
|
|
Intangible assets, net
|
|
|
187,858
|
|
|
|
190,376
|
|
Investment in unconsolidated affiliates
|
|
|
613,825
|
|
|
|
618,503
|
|
Escrow cash
|
|
|
1,858
|
|
|
|
1,858
|
|
Risk management assets
|
|
|
17,170
|
|
|
|
15,381
|
|
Other assets, net
|
|
|
21,488
|
|
|
|
22,571
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,870,098
|
|
|
$
|
1,867,412
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
112,590
|
|
|
$
|
111,021
|
|
Accrued interest
|
|
|
9,935
|
|
|
|
11,921
|
|
Accrued tax liability
|
|
|
879
|
|
|
|
672
|
|
Risk management liabilities
|
|
|
7,426
|
|
|
|
9,671
|
|
Other current liabilities
|
|
|
15,788
|
|
|
|
9,358
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
146,618
|
|
|
|
142,643
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (includes $608 and $628 bond premium as of
March 31, 2010 and December 31, 2009, respectively)
|
|
|
717,798
|
|
|
|
852,818
|
|
Deferred tax provision
|
|
|
1,889
|
|
|
|
1,862
|
|
Risk management and other noncurrent liabilities
|
|
|
7,474
|
|
|
|
10,063
|
|
Commitments and contingencies (Note 9)
|
|
|
|
|
|
|
|
|
Members capital:
|
|
|
|
|
|
|
|
|
Common units, no par value, 65,468,775 units and
54,670,029 units issued and outstanding as of
March 31, 2010 and December 31, 2009, respectively
|
|
|
1,156,889
|
|
|
|
879,504
|
|
Class D units, no par value, 0 and 3,245,817 units
issued and outstanding as of March 31, 2010 and
December 31, 2009, respectively
|
|
|
|
|
|
|
112,454
|
|
Paid-in capital
|
|
|
45,624
|
|
|
|
42,518
|
|
Accumulated deficit
|
|
|
(191,432
|
)
|
|
|
(158,267
|
)
|
Accumulated other comprehensive loss
|
|
|
(14,762
|
)
|
|
|
(16,183
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
996,319
|
|
|
|
860,026
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members capital
|
|
$
|
1,870,098
|
|
|
$
|
1,867,412
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited
consolidated financial statements.
3
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands, except per unit information)
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
120,216
|
|
|
$
|
94,979
|
|
Natural gas liquids sales
|
|
|
119,318
|
|
|
|
80,831
|
|
Transportation, compression and processing fees
|
|
|
13,114
|
|
|
|
14,999
|
|
Condensate and other
|
|
|
14,018
|
|
|
|
10,269
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
266,666
|
|
|
|
201,078
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
Cost of natural gas and natural gas
liquids(1)
|
|
|
209,865
|
|
|
|
143,319
|
|
Transportation(1)
|
|
|
5,676
|
|
|
|
5,984
|
|
Operations and maintenance
|
|
|
12,103
|
|
|
|
12,672
|
|
Depreciation and amortization
|
|
|
15,201
|
|
|
|
13,105
|
|
General and administrative
|
|
|
10,542
|
|
|
|
10,725
|
|
Taxes other than income
|
|
|
1,162
|
|
|
|
786
|
|
Equity in earnings from unconsolidated affiliates
|
|
|
(1,795
|
)
|
|
|
(1,484
|
)
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
252,754
|
|
|
|
185,107
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
13,912
|
|
|
|
15,971
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest and other income
|
|
|
7
|
|
|
|
46
|
|
Gain on retirement of unsecured debt
|
|
|
|
|
|
|
3,939
|
|
Interest and other financing costs
|
|
|
(14,945
|
)
|
|
|
(14,448
|
)
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes and discontinued operations
|
|
|
(1,026
|
)
|
|
|
5,508
|
|
Provision for income taxes
|
|
|
(234
|
)
|
|
|
(164
|
)
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing operations
|
|
|
(1,260
|
)
|
|
|
5,344
|
|
Discontinued operations, net of tax (Note 13)
|
|
|
|
|
|
|
561
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,260
|
)
|
|
$
|
5,905
|
|
|
|
|
|
|
|
|
|
|
Basic net (loss) income per common unit:
|
|
|
|
|
|
|
|
|
(Loss) income per common unit from continuing operations
|
|
$
|
(0.02
|
)
|
|
$
|
0.10
|
|
Income per common unit from discontinued operations
|
|
|
|
|
|
|
0.01
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per common unit
|
|
$
|
(0.02
|
)
|
|
$
|
0.11
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common units
|
|
|
58,206
|
|
|
|
54,012
|
|
Diluted net (loss) income per common unit:
|
|
|
|
|
|
|
|
|
(Loss) income per common unit from continuing operations
|
|
$
|
(0.02
|
)
|
|
$
|
0.09
|
|
Income per common unit from discontinued operations
|
|
|
|
|
|
|
0.01
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per common unit
|
|
$
|
(0.02
|
)
|
|
$
|
0.10
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common units
|
|
|
58,206
|
|
|
|
57,814
|
|
|
|
|
(1) |
|
Exclusive of operations and maintenance and depreciation and
amortization shown separately below. |
The accompanying notes are an integral part of these unaudited
consolidated financial statements.
4
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Cash Flows From Operating Activities:
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,260
|
)
|
|
$
|
5,905
|
|
Adjustments to reconcile net (loss) income to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
15,201
|
|
|
|
13,165
|
|
Amortization of debt issue costs
|
|
|
895
|
|
|
|
1,270
|
|
Equity in earnings from unconsolidated affiliates
|
|
|
(1,795
|
)
|
|
|
(1,484
|
)
|
Distributions from unconsolidated affiliates
|
|
|
5,765
|
|
|
|
5,371
|
|
Gain on retirement of unsecured debt
|
|
|
|
|
|
|
(3,939
|
)
|
Non-cash loss (gain) on risk management activities, net
|
|
|
533
|
|
|
|
(239
|
)
|
Equity-based compensation
|
|
|
2,703
|
|
|
|
1,705
|
|
Deferred tax provision
|
|
|
27
|
|
|
|
12
|
|
Other non-cash items
|
|
|
(301
|
)
|
|
|
332
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
2,124
|
|
|
|
28,277
|
|
Prepayments and other current assets
|
|
|
1,167
|
|
|
|
1,060
|
|
Risk management activities
|
|
|
597
|
|
|
|
9,188
|
|
Accounts payable
|
|
|
2,063
|
|
|
|
(22,925
|
)
|
Other current liabilities
|
|
|
1,445
|
|
|
|
(2,300
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
29,164
|
|
|
|
35,398
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities:
|
|
|
|
|
|
|
|
|
Additions to property, plant and equipment
|
|
|
(19,162
|
)
|
|
|
(19,423
|
)
|
Additions to intangible assets
|
|
|
(263
|
)
|
|
|
(417
|
)
|
Investment in unconsolidated affiliates
|
|
|
(435
|
)
|
|
|
(632
|
)
|
Distributions from unconsolidated affiliates
|
|
|
972
|
|
|
|
1,560
|
|
Proceeds from sale of assets
|
|
|
259
|
|
|
|
|
|
Other
|
|
|
188
|
|
|
|
(539
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(18,441
|
)
|
|
|
(19,451
|
)
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities:
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
35,000
|
|
|
|
50,000
|
|
Repayment of long-term debt
|
|
|
(170,000
|
)
|
|
|
|
|
Retirement of unsecured debt
|
|
|
|
|
|
|
(14,286
|
)
|
Distributions to unitholders
|
|
|
(31,457
|
)
|
|
|
(31,057
|
)
|
Proceeds from public offering of common units, net of
underwriting discounts and commissions of $7,223
|
|
|
164,786
|
|
|
|
|
|
Equity offering costs
|
|
|
(272
|
)
|
|
|
|
|
Proceeds from option exercises
|
|
|
676
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by financing activities
|
|
|
(1,267
|
)
|
|
|
4,662
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
9,456
|
|
|
|
20,609
|
|
Cash and cash equivalents, beginning of year
|
|
|
44,692
|
|
|
|
63,684
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
54,148
|
|
|
$
|
84,293
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited
consolidated financial statements.
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
Class C
|
|
|
Class D
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
Total
|
|
|
|
Number
|
|
|
Common
|
|
|
Number
|
|
|
Class C
|
|
|
Number
|
|
|
Class D
|
|
|
Paid-in
|
|
|
Accumulated
|
|
|
Comprehensive
|
|
|
|
|
|
Comprehensive
|
|
|
|
of Units
|
|
|
Units
|
|
|
of Units
|
|
|
Units
|
|
|
of Units
|
|
|
Units
|
|
|
Capital
|
|
|
Deficit
|
|
|
(Loss) Income
|
|
|
Total
|
|
|
Income (Loss)
|
|
|
Balance, December 31, 2009
|
|
|
54,670
|
|
|
$
|
879,504
|
|
|
|
|
|
|
$
|
|
|
|
|
3,246
|
|
|
$
|
112,454
|
|
|
$
|
42,518
|
|
|
$
|
(158,267
|
)
|
|
$
|
(16,183
|
)
|
|
$
|
860,026
|
|
|
|
|
|
Conversion of Class D units into common units
|
|
|
3,246
|
|
|
|
112,454
|
|
|
|
|
|
|
|
|
|
|
|
(3,246
|
)
|
|
|
(112,454
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
Distributions to unitholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,905
|
)
|
|
|
|
|
|
|
(31,905
|
)
|
|
|
|
|
Issuance of common units to public
|
|
|
7,446
|
|
|
|
172,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172,008
|
|
|
|
|
|
Equity offering costs
|
|
|
|
|
|
|
(7,753
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,753
|
)
|
|
|
|
|
Equity-based compensation
|
|
|
107
|
|
|
|
676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,106
|
|
|
|
|
|
|
|
|
|
|
|
3,782
|
|
|
|
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,260
|
)
|
|
|
|
|
|
|
(1,260
|
)
|
|
|
(1,260
|
)
|
Derivative settlements reclassified to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
855
|
|
|
|
855
|
|
|
|
855
|
|
Unrealized gain-change in fair value of derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
566
|
|
|
|
566
|
|
|
|
566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
161
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2010
|
|
|
65,469
|
|
|
$
|
1,156,889
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
45,624
|
|
|
$
|
(191,432
|
)
|
|
$
|
(14,762
|
)
|
|
$
|
996,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
Class C
|
|
|
Class D
|
|
|
|
|
|
Accumulated
|
|
|
Other
|
|
|
|
|
|
Total
|
|
|
|
Number
|
|
|
Common
|
|
|
Number
|
|
|
Class C
|
|
|
Number
|
|
|
Class D
|
|
|
Paid-in
|
|
|
Earnings
|
|
|
Comprehensive
|
|
|
|
|
|
Comprehensive
|
|
|
|
of Units
|
|
|
Units
|
|
|
of Units
|
|
|
Units
|
|
|
of Units
|
|
|
Units
|
|
|
Capital
|
|
|
(Deficit)
|
|
|
Income (Loss)
|
|
|
Total
|
|
|
Income (Loss)
|
|
|
|
(In thousands)
|
|
|
Balance, December 31, 2008
|
|
|
53,965
|
|
|
$
|
865,343
|
|
|
|
395
|
|
|
$
|
13,497
|
|
|
|
3,246
|
|
|
$
|
112,454
|
|
|
$
|
33,734
|
|
|
$
|
(54,696
|
)
|
|
$
|
67,626
|
|
|
$
|
1,037,958
|
|
|
|
|
|
Distributions to unitholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,462
|
)
|
|
|
|
|
|
|
(31,462
|
)
|
|
$
|
|
|
Equity-based compensation
|
|
|
104
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,156
|
|
|
|
|
|
|
|
|
|
|
|
3,161
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,905
|
|
|
|
|
|
|
|
5,905
|
|
|
|
5,905
|
|
Derivative settlements reclassified to income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,696
|
)
|
|
|
(14,696
|
)
|
|
|
(14,696
|
)
|
Unrealized gain-change in fair value of derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,013
|
|
|
|
7,013
|
|
|
|
7,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,778
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2009
|
|
|
54,069
|
|
|
$
|
865,348
|
|
|
|
395
|
|
|
$
|
13,497
|
|
|
|
3,246
|
|
|
$
|
112,454
|
|
|
$
|
36,890
|
|
|
$
|
(80,253
|
)
|
|
$
|
59,943
|
|
|
$
|
1,007,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited
consolidated financial statements.
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
Note 1 Organization
and Basis of Presentation
Organization
Copano Energy, L.L.C., a Delaware limited liability company, was
formed in August 2001 to acquire entities owning businesses
operating under the Copano name since 1992. We, through our
subsidiaries, provide midstream services to natural gas
producers, including natural gas gathering, compression,
dehydration, treating, marketing, transportation, processing,
conditioning and fractionation services. Our assets are located
in Oklahoma, Texas, Wyoming and Louisiana. Unless the context
requires otherwise, references to Copano,
we, our, us or like terms
refer to Copano Energy, L.L.C., its subsidiaries and entities it
manages or operates.
Our natural gas pipelines collect natural gas from wellheads or
designated points near producing wells and deliver these volumes
to our processing plants, third-party processing plants,
third-party pipelines, local distribution companies, power
generation facilities and industrial consumers. Our processing
plants take delivery of natural gas from our gathering systems
as well as third-party pipelines. The natural gas is then
treated as needed to remove contaminants and then conditioned or
processed to extract mixed NGLs. After treating and processing
or conditioning, we deliver the residue gas primarily to
third-party pipelines through plant interconnects and sell the
NGLs, in some cases after separating the NGLs into select
component products, to third parties through our plant
interconnects or our NGL pipelines. We refer to our operations
(i) conducted through our subsidiaries operating in
Oklahoma, including our crude oil pipeline which was sold in
October 2009, collectively as our Oklahoma segment,
(ii) conducted through our subsidiaries operating in Texas
and Louisiana collectively as our Texas segment and
(iii) conducted through our subsidiaries operating in
Wyoming collectively as our Rocky Mountains segment.
Basis
of Presentation and Principles of Consolidation
The accompanying unaudited consolidated financial statements and
related notes include our assets, liabilities and results of
operations for each of the periods presented. All intercompany
accounts and transactions are eliminated in our unaudited
consolidated financial statements.
Because we sold our crude oil pipeline operations in October
2009, the results related to these operations have been
classified as discontinued operations on the
accompanying unaudited consolidated statements of operations for
the three months ended March 31, 2009. Unless otherwise
indicated, information about the statements of operations that
is presented in the notes to unaudited consolidated financial
statements relates only to our continuing operations. See
Note 13 for additional details.
The accompanying unaudited consolidated financial statements
have been prepared without audit pursuant to the rules and
regulations of the Securities and Exchange Commission
(SEC). Accordingly, our financial statements reflect
all normal and recurring adjustments that are, in the opinion of
our management, necessary for a fair presentation of our results
of operations for the interim periods. Certain information and
notes normally included in financial statements prepared in
accordance with generally accepted accounting principles have
been condensed or omitted pursuant to such rules and regulations.
However, our management believes that the disclosures are
adequate to make the information presented not misleading. In
the preparation of these financial statements, we evaluated
subsequent events through the issuance date of the financial
statements. These interim financial statements should be read in
conjunction with the audited consolidated financial statements
and notes thereto contained in our Annual Report on
Form 10-K
and Amendment No. 1 for the year ended December 31,
2009.
7
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 2 New
Accounting Pronouncements
Fair
Value Measurements
In January 2010, the Financial Accounting Standards Board
(FASB) issued Accounting Standards Update
(ASU)
No. 2010-06,
Fair Value Measurements and Disclosures: Improving
Disclosures about Fair Value Measurements, which
updates Accounting Standards Codification (ASC)
820-10 to
require new disclosure of amounts transferred in and out of
Level 1 and Level 2 of the fair value hierarchy and
presentation of a reconciliation of changes in fair value
amounts in the Level 3 fair value hierarchy on a gross
basis rather than a net basis. Additionally, ASU
2010-06
requires greater disaggregation of the assets and liabilities
for which fair value measurements are presented and requires
expanded disclosure of the valuation techniques and inputs used
for Level 2 and Level 3 fair value measurements. We
implemented ASU
2010-06 as
of March 31, 2010. See Note 11 for the required
additional disclosures.
Note 3 Intangible
Assets
Our intangible assets consist of
rights-of-way,
easements, contracts and acquired customer relationships. We
amortize existing intangible assets and any costs incurred to
renew or extend the terms of existing intangible assets over the
contract term or estimated useful life, as applicable. Upon
adoption of the
ASC 350-30,
initial costs of acquiring new intangible assets are amortized
over the estimated useful life of the related tangible assets.
Any related renewals or extension costs of intangible assets are
expensed over the contract term using the straight-line method.
Amortization expense was $2,780,000 and $2,751,000 for the three
months ended March 31, 2010 and 2009, respectively.
Estimated aggregate amortization expense remaining for 2010 and
each of the five succeeding fiscal years is approximately:
2010 $8,291,000; 2011
$11,055,000; 2012 $10,991,000;
2013 $10,810,000; 2014
$10,643,000; and 2015 $10,608,000.
Intangible assets consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Rights-of-way
and easements, at cost
|
|
$
|
116,384
|
|
|
$
|
116,122
|
|
Less accumulated amortization for
rights-of-way
and easements
|
|
|
(19,450
|
)
|
|
|
(18,204
|
)
|
Contracts
|
|
|
107,916
|
|
|
|
107,916
|
|
Less accumulated amortization for contracts
|
|
|
(20,786
|
)
|
|
|
(19,330
|
)
|
Customer relationships
|
|
|
4,864
|
|
|
|
4,864
|
|
Less accumulated amortization for customer relationships
|
|
|
(1,070
|
)
|
|
|
(992
|
)
|
|
|
|
|
|
|
|
|
|
Intangible assets, net
|
|
$
|
187,858
|
|
|
$
|
190,376
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2010 and 2009, the weighted average
amortization period for all of our intangible assets was
20 years and 21 years, respectively. The weighted
average amortization period for our
rights-of-way
and easements, contracts and customer relationships was
22 years, 18 years and 12 years, respectively, as
of March 31, 2010. The weighted average amortization period
for our
rights-of-way
and easements, contracts and customer relationships was
23 years, 19 years and 13 years, respectively, as
of March 31, 2009.
Note 4 Investment
in Unconsolidated Affiliates
We own a 62.5% equity investment in Webb/Duval Gatherers
(Webb Duval), a Texas general partnership, a
majority interest in Southern Dome, LLC (Southern
Dome), a Delaware limited liability company, a 51% equity
investment in Bighorn Gas Gathering, L.L.C.
(Bighorn), a Delaware limited liability company and
a 37.04% equity investment in Fort Union Gas Gathering,
L.L.C. (Fort Union), a Delaware limited
liability company.
8
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 4 Investment
in Unconsolidated Affiliates (Continued)
No restrictions exist under Webb Duvals, Southern
Domes, or Bighorns partnership or operating
agreements that limit these entities ability to pay
distributions to their respective partners or members after
consideration of their respective current and anticipated cash
needs, including debt service obligations. Fort Union can
distribute cash to its members only if its ratio of net
operating cash flow to debt service is not less than 1.25 to
1.00 and it is not otherwise in default under its credit
agreement. If Fort Union fails to comply with this covenant
or otherwise defaults under its credit agreement, it would be
prohibited from distributing cash. As of March 31, 2010,
Fort Union is in compliance with all financial covenants.
The summarized financial information for our equity investments
as of and for the three months ended March 31, 2010 is as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bighorn
|
|
|
Fort Union
|
|
|
Southern Dome
|
|
|
Webb Duval
|
|
|
Operating revenue
|
|
$
|
8,049
|
|
|
$
|
14,160
|
|
|
$
|
7,687
|
|
|
$
|
511
|
|
Operating expenses
|
|
|
(3,122
|
)
|
|
|
(2,189
|
)
|
|
|
(6,162
|
)
|
|
|
(518
|
)
|
Depreciation and amortization
|
|
|
(1,270
|
)
|
|
|
(1,730
|
)
|
|
|
(186
|
)
|
|
|
(191
|
)
|
Interest income (expense) and other
|
|
|
4
|
|
|
|
(1,002
|
)
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
3,661
|
|
|
|
9,239
|
|
|
|
1,341
|
|
|
|
(198
|
)
|
Ownership %
|
|
|
51
|
%
|
|
|
37.04
|
%
|
|
|
69.5
|
%
|
|
|
62.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,867
|
|
|
|
3,422
|
|
|
|
932
|
|
|
|
(124
|
)
|
Priority allocation of earnings and other
|
|
|
170
|
|
|
|
|
|
|
|
(18
|
)
|
|
|
|
|
Copanos share of management fees charged
|
|
|
71
|
|
|
|
22
|
|
|
|
43
|
|
|
|
35
|
|
Amortization of difference between the carried investment and
the underlying equity in net assets
|
|
|
(3,042
|
)
|
|
|
(1,606
|
)
|
|
|
(2
|
)
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in (loss) earnings from unconsolidated affiliates
|
|
$
|
(934
|
)
|
|
$
|
1,838
|
|
|
$
|
955
|
|
|
$
|
(84
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
|
|
$
|
2,897
|
|
|
$
|
2,778
|
|
|
$
|
1,043
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
6,572
|
|
|
$
|
12,619
|
|
|
$
|
3,986
|
|
|
$
|
430
|
|
Noncurrent assets
|
|
|
91,897
|
|
|
|
211,094
|
|
|
|
15,381
|
|
|
|
5,995
|
|
Current liabilities
|
|
|
(1,383
|
)
|
|
|
(21,451
|
)
|
|
|
(5,244
|
)
|
|
|
(945
|
)
|
Noncurrent liabilities
|
|
|
(244
|
)
|
|
|
(84,592
|
)
|
|
|
|
|
|
|
(59
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets
|
|
$
|
96,842
|
|
|
$
|
117,670
|
|
|
$
|
14,123
|
|
|
$
|
5,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 4 Investment
in Unconsolidated Affiliates (Continued)
The summarized financial information for our equity investments
as of and for the three months ended March 31, 2009 is as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bighorn
|
|
|
Fort Union
|
|
|
Southern Dome
|
|
|
Webb Duval
|
|
|
Operating revenue
|
|
$
|
8,900
|
|
|
$
|
15,121
|
|
|
$
|
3,247
|
|
|
$
|
498
|
|
Operating expenses
|
|
|
(3,315
|
)
|
|
|
(1,439
|
)
|
|
|
(2,808
|
)
|
|
|
(395
|
)
|
Depreciation and amortization
|
|
|
(1,142
|
)
|
|
|
(1,948
|
)
|
|
|
(187
|
)
|
|
|
(197
|
)
|
Interest (expense) income and other
|
|
|
|
|
|
|
(1,365
|
)
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
4,443
|
|
|
|
10,369
|
|
|
|
254
|
|
|
|
(94
|
)
|
Ownership %
|
|
|
51
|
%
|
|
|
37.04
|
%
|
|
|
69.5
|
%
|
|
|
62.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,266
|
|
|
|
3,841
|
|
|
|
176
|
|
|
|
(59
|
)
|
Priority allocation of earnings and other
|
|
|
148
|
|
|
|
(225
|
)
|
|
|
|
|
|
|
|
|
Copanos share of management fees charged
|
|
|
60
|
|
|
|
21
|
|
|
|
43
|
|
|
|
34
|
|
Amortization of difference between the carried investment and
the underlying equity in net assets
|
|
|
(3,215
|
)
|
|
|
(1,606
|
)
|
|
|
(2
|
)
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in (loss) earnings from unconsolidated affiliates
|
|
$
|
(741
|
)
|
|
$
|
2,031
|
|
|
$
|
217
|
|
|
$
|
(20
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
|
|
$
|
3,209
|
|
|
$
|
2,778
|
|
|
$
|
626
|
|
|
$
|
281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
9,037
|
|
|
$
|
15,086
|
|
|
$
|
2,372
|
|
|
$
|
627
|
|
Noncurrent assets
|
|
|
97,145
|
|
|
|
213,672
|
|
|
|
16,190
|
|
|
|
6,756
|
|
Current liabilities
|
|
|
(2,091
|
)
|
|
|
(20,243
|
)
|
|
|
(3,107
|
)
|
|
|
(471
|
)
|
Noncurrent liabilities
|
|
|
|
|
|
|
(99,708
|
)
|
|
|
|
|
|
|
(55
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets
|
|
$
|
104,091
|
|
|
$
|
108,807
|
|
|
$
|
15,455
|
|
|
$
|
6,857
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 5 Long-Term
Debt
A summary of our debt follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
Credit Facility
|
|
$
|
135,000
|
|
|
$
|
270,000
|
|
Senior Notes:
|
|
|
|
|
|
|
|
|
8.125% senior unsecured notes due 2016
|
|
|
332,665
|
|
|
|
332,665
|
|
Unamortized bond premium-senior notes due 2016
|
|
|
608
|
|
|
|
628
|
|
7.75% senior unsecured notes due 2018
|
|
|
249,525
|
|
|
|
249,525
|
|
|
|
|
|
|
|
|
|
|
Total Senior Notes
|
|
|
582,798
|
|
|
|
582,818
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
717,798
|
|
|
$
|
852,818
|
|
|
|
|
|
|
|
|
|
|
10
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 5 Long-Term
Debt (Continued)
Senior
Secured Revolving Credit Facility
As of March 31, 2010, we had $135.0 million of
outstanding borrowings under our $550 million senior
secured revolving credit facility (the Credit
Facility) with Bank of America, N.A., as Administrative
Agent. The Credit Facility matures on October 18, 2012.
Future borrowings under the Credit Facility are available for
acquisitions, capital expenditures, working capital and general
corporate purposes, and the facility may be drawn on and repaid
without restrictions so long as we are in compliance with its
terms, including the financial covenants described below. The
Credit Facility provides for up to $50.0 million in standby
letters of credit. As of March 31, 2010 and
December 31, 2009, we had no letters of credit outstanding.
The effective average interest rate on borrowings under the
Credit Facility for the three months ended March 31, 2010
and 2009 was 5.3% and 4.8%, respectively, and the quarterly
commitment fee on the unused portion of the Credit Facility for
those periods was 0.25%. Interest and other financing costs
related to the Credit Facility totaled $1,920,000 and $2,970,000
for the three months ended March 31, 2010 and 2009,
respectively. Costs incurred in connection with the
establishment of this credit facility are being amortized over
the term of the Credit Facility, and as of March 31, 2010,
the unamortized portion of debt issue costs totaled $5,454,000.
The Credit Facility contains covenants (some of which require
that we make certain subjective representations and warranties),
including financial covenants that require us and our subsidiary
guarantors, on a consolidated basis, to maintain specified
ratios as follows:
|
|
|
|
|
a minimum EBITDA to interest expense ratio (using four
quarters EBITDA as defined under the Credit Facility) of
2.5 to 1.0;
|
|
|
|
a maximum total debt to EBITDA ratio of 5.0 to 1.0 (with no
future reductions) with the option to increase the total debt to
EBITDA ratio to not more than 5.5 to 1.0 for a period of up to
nine months following an acquisition or a series of acquisitions
totaling $50 million in a
12-month
period (subject to an increased applicable interest rate margin
and commitment fee rate).
|
EBITDA for the purposes of the Credit Facility is our EBITDA
with certain negotiated adjustments.
At March 31, 2010, our ratio of EBITDA to interest expense
was 3.5x, and our ratio of total debt to EBITDA was 3.7x. Based
on our current
four-quarter
EBITDA, as defined under the Credit Facility, we could borrow an
additional $247 million before reaching our maximum total
debt to EBITDA ratio of 5.0 to 1.0. If we failed to comply with
the financial or other covenants under our Credit Facility or
experienced a material adverse effect on our operations,
business, properties, liabilities or financial or other
condition, we would be unable to borrow under our Credit
Facility, and could be in default after specified notice and
cure periods. If an event of default exists under the Credit
Facility, our lenders could terminate their commitments to lend
to us and accelerate the maturity of our outstanding obligations
under the Credit Facility.
We are in compliance with the financial covenants under the
Credit Facility as of March 31, 2010.
Senior
Notes
8.125% Senior Notes Due 2016. At
March 31, 2010, the aggregate principal amount of our
8.125% senior unsecured notes due 2016 (the 2016
Notes) outstanding was $332,665,000.
Interest and other financing costs related to the 2016 Notes
totaled $6,951,000 and $6,953,000 for the three months ended
March 31, 2010 and 2009, respectively. Interest on the 2016
Notes is payable each March 1 and September 1. Costs of
issuing the 2016 Notes are being amortized over the term of the
2016 Notes and, as of March 31, 2010, the unamortized
portion of debt issue costs totaled $5,061,000.
11
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 5 Long-Term
Debt (Continued)
7.75% Senior Notes Due 2018. At
March 31, 2010, the aggregate principal amount of
7.75% senior unsecured notes due 2018 (the 2018
Notes and, together with the 2016 Notes, the Senior
Notes) outstanding was $249,525,000.
Interest and other financing costs relating to the 2018 Notes
totaled $4,971,000 and $5,523,000 for the three months ended
March 31, 2010 and 2009, respectively. Interest on the 2018
Notes is payable each June 1 and December 1. Costs of
issuing the 2018 Notes are being amortized over the term of the
2018 Notes and, as of March 31, 2010, the unamortized
portion of debt issue costs totaled $4,444,000.
General. The indentures governing our Senior
Notes include an incurrence covenant which restricts our ability
to pay cash distributions. Before we can pay a distribution to
our unitholders, we must demonstrate that our ratio of EBITDA to
fixed charges (as defined in the Senior Notes indentures) is at
least 1.75x. For the twelve months ended March 31, 2010,
our ratio of EBITDA to fixed charges was 3.3x, which is in
compliance with this incurrence covenant under the indentures
governing our Senior Notes.
Condensed consolidating financial information for Copano and its
wholly owned subsidiaries is presented below.
12
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 5 Long
Term Debt (Continued)
CONDENSED
CONSOLIDATING BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Co-Issuer
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Total
|
|
|
Parent
|
|
|
Co-Issuer
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
13,054
|
|
|
$
|
|
|
|
$
|
41,094
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
54,148
|
|
|
$
|
3,861
|
|
|
$
|
|
|
|
$
|
40,831
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
44,692
|
|
Accounts receivable, net
|
|
|
66
|
|
|
|
|
|
|
|
89,137
|
|
|
|
|
|
|
|
|
|
|
|
89,203
|
|
|
|
29
|
|
|
|
|
|
|
|
91,127
|
|
|
|
|
|
|
|
|
|
|
|
91,156
|
|
Intercompany receivable
|
|
|
14,253
|
|
|
|
(1
|
)
|
|
|
(14,252
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,034
|
|
|
|
|
|
|
|
(21,034
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk management assets
|
|
|
|
|
|
|
|
|
|
|
30,334
|
|
|
|
|
|
|
|
|
|
|
|
30,334
|
|
|
|
|
|
|
|
|
|
|
|
36,615
|
|
|
|
|
|
|
|
|
|
|
|
36,615
|
|
Prepayments and other current assets
|
|
|
2,356
|
|
|
|
|
|
|
|
1,414
|
|
|
|
|
|
|
|
|
|
|
|
3,770
|
|
|
|
3,610
|
|
|
|
|
|
|
|
1,327
|
|
|
|
|
|
|
|
|
|
|
|
4,937
|
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
29,729
|
|
|
|
(1
|
)
|
|
|
147,727
|
|
|
|
|
|
|
|
|
|
|
|
177,455
|
|
|
|
28,534
|
|
|
|
|
|
|
|
148,866
|
|
|
|
|
|
|
|
|
|
|
|
177,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
86
|
|
|
|
|
|
|
|
850,358
|
|
|
|
|
|
|
|
|
|
|
|
850,444
|
|
|
|
96
|
|
|
|
|
|
|
|
841,227
|
|
|
|
|
|
|
|
|
|
|
|
841,323
|
|
Intangible assets, net
|
|
|
|
|
|
|
|
|
|
|
187,858
|
|
|
|
|
|
|
|
|
|
|
|
187,858
|
|
|
|
|
|
|
|
|
|
|
|
190,376
|
|
|
|
|
|
|
|
|
|
|
|
190,376
|
|
Investment in unconsolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
613,825
|
|
|
|
613,825
|
|
|
|
(613,825
|
)
|
|
|
613,825
|
|
|
|
|
|
|
|
|
|
|
|
618,503
|
|
|
|
618,503
|
|
|
|
(618,503
|
)
|
|
|
618,503
|
|
Investment in consolidated subsidiaries
|
|
|
1,685,254
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,685,254
|
)
|
|
|
|
|
|
|
1,684,994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,684,994
|
)
|
|
|
|
|
Escrow cash
|
|
|
|
|
|
|
|
|
|
|
1,858
|
|
|
|
|
|
|
|
|
|
|
|
1,858
|
|
|
|
|
|
|
|
|
|
|
|
1,858
|
|
|
|
|
|
|
|
|
|
|
|
1,858
|
|
Risk management assets
|
|
|
|
|
|
|
|
|
|
|
17,170
|
|
|
|
|
|
|
|
|
|
|
|
17,170
|
|
|
|
|
|
|
|
|
|
|
|
15,381
|
|
|
|
|
|
|
|
|
|
|
|
15,381
|
|
Other assets, net
|
|
|
14,959
|
|
|
|
|
|
|
|
6,529
|
|
|
|
|
|
|
|
|
|
|
|
21,488
|
|
|
|
15,854
|
|
|
|
|
|
|
|
6,717
|
|
|
|
|
|
|
|
|
|
|
|
22,571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,730,028
|
|
|
$
|
(1
|
)
|
|
$
|
1,825,325
|
|
|
$
|
613,825
|
|
|
$
|
(2,299,079
|
)
|
|
$
|
1,870,098
|
|
|
$
|
1,729,478
|
|
|
$
|
|
|
|
$
|
1,822,928
|
|
|
$
|
618,503
|
|
|
$
|
(2,303,497
|
)
|
|
$
|
1,867,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS/PARTNERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
419
|
|
|
$
|
|
|
|
$
|
112,171
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
112,590
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
111,021
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
111,021
|
|
Accrued interest
|
|
|
9,176
|
|
|
|
|
|
|
|
759
|
|
|
|
|
|
|
|
|
|
|
|
9,935
|
|
|
|
11,146
|
|
|
|
|
|
|
|
775
|
|
|
|
|
|
|
|
|
|
|
|
11,921
|
|
Accrued tax liability
|
|
|
879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
879
|
|
|
|
672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
672
|
|
Risk management liabilities
|
|
|
|
|
|
|
|
|
|
|
7,426
|
|
|
|
|
|
|
|
|
|
|
|
7,426
|
|
|
|
|
|
|
|
|
|
|
|
9,671
|
|
|
|
|
|
|
|
|
|
|
|
9,671
|
|
Other current liabilities
|
|
|
3,265
|
|
|
|
|
|
|
|
12,523
|
|
|
|
|
|
|
|
|
|
|
|
15,788
|
|
|
|
2,637
|
|
|
|
|
|
|
|
6,721
|
|
|
|
|
|
|
|
|
|
|
|
9,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
13,739
|
|
|
|
|
|
|
|
132,879
|
|
|
|
|
|
|
|
|
|
|
|
146,618
|
|
|
|
14,455
|
|
|
|
|
|
|
|
128,188
|
|
|
|
|
|
|
|
|
|
|
|
142,643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
717,798
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
717,798
|
|
|
|
852,818
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
852,818
|
|
Deferred tax provision
|
|
|
1,889
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,889
|
|
|
|
1,862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,862
|
|
Risk management and other noncurrent liabilities
|
|
|
283
|
|
|
|
|
|
|
|
7,191
|
|
|
|
|
|
|
|
|
|
|
|
7,474
|
|
|
|
317
|
|
|
|
|
|
|
|
9,746
|
|
|
|
|
|
|
|
|
|
|
|
10,063
|
|
Members/Partners capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
1,156,889
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,156,889
|
|
|
|
879,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
879,504
|
|
Class D units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
112,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
112,454
|
|
Paid-in capital
|
|
|
45,624
|
|
|
|
1
|
|
|
|
1,172,582
|
|
|
|
589,302
|
|
|
|
(1,761,885
|
)
|
|
|
45,624
|
|
|
|
42,518
|
|
|
|
1
|
|
|
|
1,191,268
|
|
|
|
595,775
|
|
|
|
(1,787,044
|
)
|
|
|
42,518
|
|
Accumulated (deficit) earnings
|
|
|
(191,432
|
)
|
|
|
(2
|
)
|
|
|
527,434
|
|
|
|
24,523
|
|
|
|
(551,955
|
)
|
|
|
(191,432
|
)
|
|
|
(158,267
|
)
|
|
|
(1
|
)
|
|
|
509,909
|
|
|
|
22,728
|
|
|
|
(532,636
|
)
|
|
|
(158,267
|
)
|
Other comprehensive (loss) income
|
|
|
(14,762
|
)
|
|
|
|
|
|
|
(14,761
|
)
|
|
|
|
|
|
|
14,761
|
|
|
|
(14,762
|
)
|
|
|
(16,183
|
)
|
|
|
|
|
|
|
(16,183
|
)
|
|
|
|
|
|
|
16,183
|
|
|
|
(16,183
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
996,319
|
|
|
|
(1
|
)
|
|
|
1,685,255
|
|
|
|
613,825
|
|
|
|
(2,299,079
|
)
|
|
|
996,319
|
|
|
|
860,026
|
|
|
|
|
|
|
|
1,684,994
|
|
|
|
618,503
|
|
|
|
(2,303,497
|
)
|
|
|
860,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members/partners capital
|
|
$
|
1,730,028
|
|
|
$
|
(1
|
)
|
|
$
|
1,825,325
|
|
|
$
|
613,825
|
|
|
$
|
(2,299,079
|
)
|
|
$
|
1,870,098
|
|
|
$
|
1,729,478
|
|
|
$
|
|
|
|
$
|
1,822,928
|
|
|
$
|
618,503
|
|
|
$
|
(2,303,497
|
)
|
|
$
|
1,867,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 5 Long
Term Debt (Continued)
CONDENSED
CONSOLIDATING STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Co-Issuer
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Total
|
|
|
Parent
|
|
|
Co-Issuer
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
|
|
|
$
|
|
|
|
$
|
120,216
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
120,216
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
94,979
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
94,979
|
|
Natural gas liquids sales
|
|
|
|
|
|
|
|
|
|
|
119,318
|
|
|
|
|
|
|
|
|
|
|
|
119,318
|
|
|
|
|
|
|
|
|
|
|
|
80,831
|
|
|
|
|
|
|
|
|
|
|
|
80,831
|
|
Transportation, compression and processing fees
|
|
|
|
|
|
|
|
|
|
|
13,114
|
|
|
|
|
|
|
|
|
|
|
|
13,114
|
|
|
|
|
|
|
|
|
|
|
|
14,999
|
|
|
|
|
|
|
|
|
|
|
|
14,999
|
|
Condensate and other
|
|
|
|
|
|
|
|
|
|
|
14,018
|
|
|
|
|
|
|
|
|
|
|
|
14,018
|
|
|
|
|
|
|
|
|
|
|
|
10,269
|
|
|
|
|
|
|
|
|
|
|
|
10,269
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
|
|
|
|
|
|
|
|
266,666
|
|
|
|
|
|
|
|
|
|
|
|
266,666
|
|
|
|
|
|
|
|
|
|
|
|
201,078
|
|
|
|
|
|
|
|
|
|
|
|
201,078
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of natural gas and natural gas liquids
|
|
|
|
|
|
|
|
|
|
|
209,865
|
|
|
|
|
|
|
|
|
|
|
|
209,865
|
|
|
|
|
|
|
|
|
|
|
|
143,319
|
|
|
|
|
|
|
|
|
|
|
|
143,319
|
|
Transportation
|
|
|
|
|
|
|
|
|
|
|
5,676
|
|
|
|
|
|
|
|
|
|
|
|
5,676
|
|
|
|
|
|
|
|
|
|
|
|
5,984
|
|
|
|
|
|
|
|
|
|
|
|
5,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
|
|
|
|
|
|
|
|
|
12,103
|
|
|
|
|
|
|
|
|
|
|
|
12,103
|
|
|
|
270
|
|
|
|
|
|
|
|
12,402
|
|
|
|
|
|
|
|
|
|
|
|
12,672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
10
|
|
|
|
|
|
|
|
15,191
|
|
|
|
|
|
|
|
|
|
|
|
15,201
|
|
|
|
10
|
|
|
|
|
|
|
|
13,095
|
|
|
|
|
|
|
|
|
|
|
|
13,105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
5,195
|
|
|
|
|
|
|
|
5,347
|
|
|
|
|
|
|
|
|
|
|
|
10,542
|
|
|
|
6,451
|
|
|
|
|
|
|
|
4,274
|
|
|
|
|
|
|
|
|
|
|
|
10,725
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes other than income
|
|
|
|
|
|
|
|
|
|
|
1,162
|
|
|
|
|
|
|
|
|
|
|
|
1,162
|
|
|
|
|
|
|
|
|
|
|
|
786
|
|
|
|
|
|
|
|
|
|
|
|
786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings from unconsolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
(1,795
|
)
|
|
|
(1,795
|
)
|
|
|
1,795
|
|
|
|
(1,795
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,484
|
)
|
|
|
(1,484
|
)
|
|
|
1,484
|
|
|
|
(1,484
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
5,205
|
|
|
|
|
|
|
|
247,549
|
|
|
|
(1,795
|
)
|
|
|
1,795
|
|
|
|
252,754
|
|
|
|
6,731
|
|
|
|
|
|
|
|
178,376
|
|
|
|
(1,484
|
)
|
|
|
1,484
|
|
|
|
185,107
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
|
(5,205
|
)
|
|
|
|
|
|
|
19,117
|
|
|
|
1,795
|
|
|
|
(1,795
|
)
|
|
|
13,912
|
|
|
|
(6,731
|
)
|
|
|
|
|
|
|
22,702
|
|
|
|
1,484
|
|
|
|
(1,484
|
)
|
|
|
15,971
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other income
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
46
|
|
Gain on retirement of unsecured debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,939
|
|
Interest and other financing costs
|
|
|
(13,347
|
)
|
|
|
|
|
|
|
(1,598
|
)
|
|
|
|
|
|
|
|
|
|
|
(14,945
|
)
|
|
|
(13,417
|
)
|
|
|
|
|
|
|
(1,031
|
)
|
|
|
|
|
|
|
|
|
|
|
(14,448
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes, discontinued operations and
equity in earnings from consolidated subsidiaries
|
|
|
(18,552
|
)
|
|
|
|
|
|
|
17,526
|
|
|
|
1,795
|
|
|
|
(1,795
|
)
|
|
|
(1,026
|
)
|
|
|
(16,209
|
)
|
|
|
|
|
|
|
21,717
|
|
|
|
1,484
|
|
|
|
(1,484
|
)
|
|
|
5,508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income taxes
|
|
|
(234
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(234
|
)
|
|
|
(164
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(164
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before discontinued operations and equity in
earnings from consolidated subsidiaries
|
|
|
(18,786
|
)
|
|
|
|
|
|
|
17,526
|
|
|
|
1,795
|
|
|
|
(1,795
|
)
|
|
|
(1,260
|
)
|
|
|
(16,373
|
)
|
|
|
|
|
|
|
21,717
|
|
|
|
1,484
|
|
|
|
(1,484
|
)
|
|
|
5,344
|
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
561
|
|
|
|
|
|
|
|
|
|
|
|
561
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before equity earnings from consolidated
subsidiaries
|
|
|
(18,786
|
)
|
|
|
|
|
|
|
17,526
|
|
|
|
1,795
|
|
|
|
(1,795
|
)
|
|
|
(1,260
|
)
|
|
|
(16,373
|
)
|
|
|
|
|
|
|
22,278
|
|
|
|
1,484
|
|
|
|
(1,484
|
)
|
|
|
5,905
|
|
Equity in earnings from consolidated subsidiaries
|
|
|
17,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17,526
|
)
|
|
|
|
|
|
|
22,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22,278
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,260
|
)
|
|
$
|
|
|
|
$
|
17,526
|
|
|
$
|
1,795
|
|
|
$
|
(19,321
|
)
|
|
$
|
(1,260
|
)
|
|
$
|
5,905
|
|
|
$
|
|
|
|
$
|
22,278
|
|
|
$
|
1,484
|
|
|
$
|
(23,762
|
)
|
|
$
|
5,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 5 Long
Term Debt (Continued)
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Month Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Co-Issuer
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Total
|
|
|
Parent
|
|
|
Co-Issuer
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Cash Flows From Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
(12,540
|
)
|
|
$
|
|
|
|
$
|
41,704
|
|
|
$
|
5,765
|
|
|
$
|
(5,765
|
)
|
|
$
|
29,164
|
|
|
$
|
8,667
|
|
|
$
|
|
|
|
$
|
26,731
|
|
|
$
|
5,371
|
|
|
$
|
(5,371
|
)
|
|
$
|
35,398
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property, plant and equipment
|
|
|
|
|
|
|
|
|
|
|
(19,425
|
)
|
|
|
|
|
|
|
|
|
|
|
(19,425
|
)
|
|
|
|
|
|
|
|
|
|
|
(19,840
|
)
|
|
|
|
|
|
|
|
|
|
|
(19,840
|
)
|
Investment in unconsolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
(435
|
)
|
|
|
(435
|
)
|
|
|
435
|
|
|
|
(435
|
)
|
|
|
|
|
|
|
|
|
|
|
(632
|
)
|
|
|
(632
|
)
|
|
|
632
|
|
|
|
(632
|
)
|
Distributions from unconsolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
972
|
|
|
|
972
|
|
|
|
(972
|
)
|
|
|
972
|
|
|
|
|
|
|
|
|
|
|
|
1,560
|
|
|
|
1,560
|
|
|
|
(1,560
|
)
|
|
|
1,560
|
|
Investment in consolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(25
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
Distributions from consolidated affiliates
|
|
|
23,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23,000
|
)
|
|
|
|
|
|
|
6,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,000
|
)
|
|
|
|
|
Proceeds from sale of assets
|
|
|
|
|
|
|
|
|
|
|
259
|
|
|
|
|
|
|
|
|
|
|
|
259
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
188
|
|
|
|
|
|
|
|
|
|
|
|
188
|
|
|
|
|
|
|
|
|
|
|
|
(539
|
)
|
|
|
|
|
|
|
|
|
|
|
(539
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities
|
|
|
23,000
|
|
|
|
|
|
|
|
(18,441
|
)
|
|
|
537
|
|
|
|
(23,537
|
)
|
|
|
(18,441
|
)
|
|
|
5,975
|
|
|
|
|
|
|
|
(19,451
|
)
|
|
|
928
|
|
|
|
(6,903
|
)
|
|
|
(19,451
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
35,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,000
|
|
|
|
50,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,000
|
|
Repayments of long-term debt
|
|
|
(170,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(170,000
|
)
|
|
|
(14,286
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,286
|
)
|
Distributions to unitholders
|
|
|
(31,457
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,457
|
)
|
|
|
(31,057
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,057
|
)
|
Equity offering of common units
|
|
|
164,786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
164,786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity offering of common units-offering costs
|
|
|
(272
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(272
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contributions from parent
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
(25
|
)
|
|
|
|
|
Distributions to parent
|
|
|
|
|
|
|
|
|
|
|
(23,000
|
)
|
|
|
|
|
|
|
23,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,000
|
)
|
|
|
|
|
|
|
6,000
|
|
|
|
|
|
Other
|
|
|
676
|
|
|
|
|
|
|
|
|
|
|
|
435
|
|
|
|
(435
|
)
|
|
|
676
|
|
|
|
10
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
632
|
|
|
|
(632
|
)
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by financing activities
|
|
|
(1,267
|
)
|
|
|
|
|
|
|
(23,000
|
)
|
|
|
435
|
|
|
|
22,565
|
|
|
|
(1,267
|
)
|
|
|
4,667
|
|
|
|
|
|
|
|
(5,980
|
)
|
|
|
632
|
|
|
|
5,343
|
|
|
|
4,662
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
|
9,193
|
|
|
|
|
|
|
|
263
|
|
|
|
6,737
|
|
|
|
(6,737
|
)
|
|
|
9,456
|
|
|
|
19,309
|
|
|
|
|
|
|
|
1,300
|
|
|
|
6,931
|
|
|
|
(6,931
|
)
|
|
|
20,609
|
|
Cash and cash equivalents, beginning of year
|
|
|
3,861
|
|
|
|
(1
|
)
|
|
|
40,832
|
|
|
|
59,896
|
|
|
|
(59,896
|
)
|
|
|
44,692
|
|
|
|
20,417
|
|
|
|
|
|
|
$
|
43,267
|
|
|
$
|
30,212
|
|
|
$
|
(30,212
|
)
|
|
$
|
63,684
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of year
|
|
$
|
13,054
|
|
|
$
|
(1
|
)
|
|
$
|
41,095
|
|
|
$
|
66,633
|
|
|
$
|
(66,633
|
)
|
|
$
|
54,148
|
|
|
$
|
39,726
|
|
|
$
|
|
|
|
$
|
44,567
|
|
|
$
|
37,143
|
|
|
$
|
(37,143
|
)
|
|
$
|
84,293
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 6 Members
Capital and Distributions
Common
Units
In March 2010, we issued 7,446,250 common units in an
underwritten public offering (including units issued upon the
underwriters exercise of their option to purchase
additional units). We used the net proceeds from the offering to
repay a portion of the outstanding indebtedness under our Credit
Facility, and we expect to use the increased borrowing capacity
as needed for capital projects, acquisitions, hedging, working
capital and general corporate purposes.
Class D
Units
Class D units totaling 3,245,817 as of December 31,
2009 converted into our common units on a
one-for-one
basis in February 2010.
Distributions
The following table summarizes our quarterly cash distributions
during 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
|
|
|
|
|
|
Quarter Ending
|
|
Per Unit
|
|
Date Declared
|
|
Record Date
|
|
Payment Date
|
|
Amount
|
|
December 31, 2009
|
|
$0.5750
|
|
January 13, 2010
|
|
February 1, 2010
|
|
February 11, 2010
|
|
$31,911,000
|
March 31, 2010
|
|
$0.5750
|
|
April 14, 2010
|
|
April 30, 2010
|
|
May 13, 2010
|
|
$38,134,000
|
Accounting
for Equity-Based Compensation
We use ASC 718 to account for equity-based compensation
expense related to awards issued under our long-term incentive
plan (LTIP). As of March 31, 2010, the number
of units available for grant under our LTIP totaled 1,676,190,
of which up to 1,075,497 units were eligible to be issued
as restricted common units, phantom units or unit awards.
Equity Awards. We recognized non-cash
compensation expense of $1,808,000 and $1,711,000 related to the
amortization of equity-based compensation under our LTIP during
the three months ended March 31, 2010 and 2009,
respectively. See Item 8 in our Annual Report on
Form 10-K
for the year ended December 31, 2009 for details on our
equity-based compensation.
Liability Awards. During the three months
ended March 31, 2010, we issued 56,223 common units to
settle our fourth quarter 2009 Employee Incentive Compensation
Program (EICP) and 2009 Management Incentive
Compensation Plan (MICP) obligations.
Since ASC 480, Accounting for Certain Financial
Instruments With Characteristics of Both Liabilities and
Equity, requires unconditional obligations in the form
of units that the issuer must or may settle by issuing a
variable number of units to be classified as a liability, we
classify equity awards issued to settle EICP and MICP
obligations as liability awards. As of March 31, 2010, we
accrued $606,000 and $326,000 for the first quarter 2010 EICP
bonuses and an estimate of the 2010 MICP incentive bonuses,
respectively. As of March 31, 2010, the estimated
unrecognized compensation costs related to these liability
awards totaled $1,819,000 and $1,196,000 for the EICP and MICP,
respectively, which are expected to be recognized as expense on
a straight-line basis through December 2010 for EICP awards and
through February 2011 for MICP awards.
Note 7 Net
Income (Loss) Per Unit
Net income (loss) per unit is calculated in accordance with
ASC 260, Earnings Per Share. ASC 260
specifies the use of the two-class method of computing earnings
per unit when participating or multiple classes of securities
16
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 7 Net
Income (Loss) Per Unit (Continued)
exist. Under this method, undistributed earnings for a period
are allocated based on the contractual rights of each security
to share in those earnings as if all of the earnings for the
period had been distributed.
Basic net income (loss) per unit excludes dilution and is
computed by dividing net income (loss) attributable to each
respective class of units by the weighted average number of
units outstanding for each respective class during the period.
Dilutive net income (loss) per unit reflects potential dilution
that could occur if convertible securities were converted into
common units or contracts to issue common units were exercised
except when the assumed conversion or exercise would have an
anti-dilutive effect on net income (loss) per unit. Dilutive net
income (loss) per unit is computed by dividing net income (loss)
attributable to each respective class of units by the weighted
average number of units outstanding for each respective class of
units during the period increased by the number of additional
units that would have been outstanding if the dilutive potential
units had been issued.
Basic and diluted net (loss) income per common unit is
calculated as follows:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands, except per unit information)
|
|
|
Net (loss) income available basic and diluted
|
|
$
|
(1,260
|
)
|
|
$
|
5,905
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average units
|
|
|
58,206
|
|
|
|
54,012
|
|
Dilutive weighted average
units(1)(2)
|
|
|
58,206
|
|
|
|
57,814
|
|
Basic net (loss) income per unit:
|
|
|
|
|
|
|
|
|
(Loss) income per unit from continuing operations
|
|
$
|
(0.02
|
)
|
|
$
|
0.10
|
|
Income per unit from discontinued operations
|
|
|
|
|
|
|
0.01
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per unit
|
|
$
|
(0.02
|
)
|
|
$
|
0.11
|
|
|
|
|
|
|
|
|
|
|
Diluted net (loss) income per unit:
|
|
|
|
|
|
|
|
|
(Loss) income per unit from continuing operations
(1)(2)
|
|
$
|
(0.02
|
)
|
|
$
|
0.09
|
|
Income per unit from discontinued operations
(1)(2)
|
|
|
|
|
|
|
0.01
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per unit
|
|
$
|
(0.02
|
)
|
|
$
|
0.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Our potentially dilutive common equity includes the following: |
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Employee options
|
|
|
|
|
|
|
76
|
|
Restricted units
|
|
|
|
|
|
|
16
|
|
Phantom units
|
|
|
|
|
|
|
11
|
|
Contingent incentive plan unit awards
|
|
|
|
|
|
|
59
|
|
Class C units
|
|
|
|
|
|
|
395
|
|
Class D units
|
|
|
|
|
|
|
3,246
|
|
17
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 7 Net
Income (Loss) Per Unit (Continued)
|
|
|
(2) |
|
The following potentially dilutive common equity was excluded
from the dilutive net income (loss) per unit calculation because
to include these equity securities would have been anti-dilutive: |
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Employee options
|
|
|
1,246
|
|
|
|
1,339
|
|
Unit appreciation rights
|
|
|
318
|
|
|
|
|
|
Restricted units
|
|
|
105
|
|
|
|
149
|
|
Phantom units
|
|
|
697
|
|
|
|
576
|
|
Class D units
|
|
|
1,561
|
|
|
|
|
|
Contingent incentive plan unit awards
|
|
|
39
|
|
|
|
|
|
Note 8 Related
Party Transactions
Natural
Gas and Related Transactions
The following table summarizes transactions between us and
affiliated entities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Affiliates of
Mr. Lawing:(1)
|
|
|
|
|
|
|
|
|
Natural gas
sales(2)
|
|
$
|
1
|
|
|
$
|
|
|
Gathering and compression
services(3)
|
|
|
2
|
|
|
|
6
|
|
Natural gas
purchases(4)
|
|
|
281
|
|
|
|
350
|
|
Reimbursable
costs(5)
|
|
|
75
|
|
|
|
|
|
Reimbursements
paid(6)
|
|
|
|
|
|
|
638
|
|
Payable by us as of March 31,
2010(7)
|
|
|
63
|
|
|
|
|
|
Webb Duval:
|
|
|
|
|
|
|
|
|
Natural gas
sales(2)
|
|
|
|
|
|
|
368
|
|
Natural gas
purchases(4)
|
|
|
53
|
|
|
|
214
|
|
Transportation
costs(8)
|
|
|
70
|
|
|
|
101
|
|
Management
fees(9)
|
|
|
56
|
|
|
|
55
|
|
Reimbursable
costs(9)
|
|
|
67
|
|
|
|
149
|
|
Payable to us as of March 31,
2010(10)
|
|
|
1,133
|
|
|
|
|
|
Payable by us as of March 31,
2010(7)
|
|
|
460
|
|
|
|
|
|
Southern Dome:
|
|
|
|
|
|
|
|
|
Management
fees(9)
|
|
|
63
|
|
|
|
63
|
|
Reimbursable
costs(9)
|
|
|
96
|
|
|
|
74
|
|
Payable to us as of March 31,
2010(10)
|
|
|
745
|
|
|
|
|
|
18
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 8
Related Party Transactions (Continued)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Bighorn:
|
|
|
|
|
|
|
|
|
Compressor rental
fees(11)
|
|
|
417
|
|
|
|
|
|
Gathering
costs(8)
|
|
|
16
|
|
|
|
107
|
|
Natural gas
purchases(4)
|
|
|
3
|
|
|
|
|
|
Management
fees(9)
|
|
|
93
|
|
|
|
72
|
|
Reimbursable
costs(9)
|
|
|
713
|
|
|
|
679
|
|
Payable to us as of March 31,
2010(10)
|
|
|
194
|
|
|
|
|
|
Payable by us as of March 31,
2010(7)
|
|
|
82
|
|
|
|
|
|
Fort Union:
|
|
|
|
|
|
|
|
|
Gathering
costs(8)
|
|
|
1,371
|
|
|
|
2,009
|
|
Treating
costs(4)
|
|
|
52
|
|
|
|
184
|
|
Management
fees(9)
|
|
|
56
|
|
|
|
57
|
|
Reimbursable
costs(9)
|
|
|
85
|
|
|
|
10
|
|
Payable to us as of March 31,
2010(10)
|
|
|
33
|
|
|
|
|
|
Payable by us as of March 31,
2010(7)
|
|
|
163
|
|
|
|
|
|
Other:
|
|
|
|
|
|
|
|
|
Natural gas
sales(2)
|
|
|
60
|
|
|
|
38
|
|
Payable to us as of March 31,
2010(10)
|
|
|
36
|
|
|
|
|
|
|
|
|
(1)
|
|
These entities were controlled by
John R. Eckel, Jr., our former Chairman and Chief Executive
Officer, until his death in November 2009, and since that time
have been controlled by Douglas L. Lawing, our Executive Vice
President, General Counsel and Secretary.
|
|
(2)
|
|
Revenues included in natural gas
sales on our consolidated statements of operations.
|
|
(3)
|
|
Revenues included in
transportation, compression and processing fees on our
consolidated statements of operations.
|
|
(4)
|
|
Included in costs of natural gas
and natural gas liquids on our consolidated statements of
operations.
|
|
(5)
|
|
Reimbursable costs received from
Copano/Operations, Inc. (Copano Operations) for its
use of shared personnel, facilities and equipment, which was the
only compensation we received from Copano Operations.
|
|
(6)
|
|
Reimbursable costs paid to Copano
Operations for our use of shared personnel, office space,
equipment, goods and services under an agreement that terminated
on January 1, 2010. Effective January 1, 2010, we
hired the personnel we share with Copano Operations, assumed
responsibility for procuring the shared office space, equipment,
goods and services and entered into a new agreement under which
Copano Operations pays us for use of our shared personnel and
other shared items.
|
|
(7)
|
|
Included in accounts payable on the
consolidated balance sheets.
|
|
(8)
|
|
Costs included in transportation on
our consolidated statements of operations.
|
|
(9)
|
|
Management fees and reimbursable
costs received from our unconsolidated affiliates consists of
the total compensation paid to us by our unconsolidated
affiliates and is included in general and administrative
expenses on our consolidated statements of operations.
|
|
(10)
|
|
Included in accounts receivable on
the consolidated balance sheets.
|
|
(11)
|
|
Revenues included in condensate and
other on our consolidated statements of operations.
|
19
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 8 Related
Party Transactions (Continued)
Our management believes that the terms and provisions of our
related party agreements are fair to us; however, we cannot be
certain that such agreements and services have terms as
favorable to us as we could obtain from unaffiliated third
parties.
Other
Transactions
Certain of our operating subsidiaries and unconsolidated
affiliates paid operating subsidiaries of Exterran Holdings,
Inc. (Exterran Holdings) for the purchase and
installation of compressors, compression services and compressor
repairs. We paid Exterran Holdings $988,000 and $1,145,000 for
the three months ended March 31, 2010 and 2009,
respectively, for their services. Ernie L. Danner, a member of
our Board of Directors, serves on the Board of Directors of
Exterran Holdings and as its President and Chief Executive
Officer. Our management believes that the terms and provisions
of our related party agreements are fair to us; however, we
cannot be certain that such agreements and services have terms
as favorable to us as we could obtain from unaffiliated third
parties.
Note 9 Commitments
and Contingencies
Commitments
For the three months ended March 31, 2010 and 2009, rental
expense for office space, leased vehicles and leased compressors
and related field equipment used in our operations totaled
$878,000 and $2,439,000, respectively.
We have both fixed and variable quantity contractual commitments
arising in the ordinary course of our natural gas marketing
activities. As of March 31, 2010, we had fixed contractual
commitments to purchase 491,000 million British thermal
units (MMBtu) of natural gas in April 2010. As of
March 31, 2010, we had fixed contractual commitments to
sell 2,228,000 MMBtu of natural gas in April 2010. All of
these contracts are based on index-related market pricing. Using
index-related market prices as of March 31, 2010, total
commitments to purchase natural gas related to such agreements
equaled $1,870,000 and total commitments to sell natural gas
under such agreements equaled $8,529,000. Our commitments to
purchase variable quantities of natural gas at index-based
prices range from contract periods extending from one month to
the life of the dedicated production. During March 2010, natural
gas volumes purchased under such contracts equaled
10,806,000 MMBtu. Our commitments to sell variable
quantities of natural gas at index-based prices range from
contract periods extending from one month to the year 2012.
During March 2010, natural gas volumes sold under such contracts
equaled 4,865,000 MMBtu.
We are party to firm transportation agreements with Wyoming
Interstate Gas Company (WIC), under which we are
obligated to pay for transportation capacity whether or not we
use such capacity. Under these agreements, we are obligated to
pay approximately $7,407,000 for the remainder of 2010,
$9,876,000 in 2011, $9,867,000 in 2012, $8,978,000 in 2013,
$5,509,000 in 2014 and $19,204,000 thereafter. The agreements
expire on December 31, 2019. All of our obligations under
these agreements are offset by capacity release agreements
between us and third parties, under which they pay for the right
to use our capacity. These capacity release agreements cover
100% of our total WIC capacity and continue through
December 31, 2019. We have placed in escrow
$1.9 million, classified as escrow cash on the consolidated
balance sheets, as credit support for our obligations under the
WIC agreements.
Additionally, we have two firm gathering agreements with
Fort Union, under which we are obligated to pay for
gathering capacity on the Fort Union system whether or not
we use such capacity. Under these agreements, we are obligated
to pay approximately $3,637,000 for the remainder of 2010,
$5,859,000 for 2011, $7,154,000 for 2012 and $7,665,000 for each
of the years thereafter. Generally, we resell our firm capacity
to third parties under various types of agreements. These
commitments expire in November 30, 2017.
We have fixed-quantity contractual commitments to Targa North
Texas LP (Targa) in settlement of a dispute
regarding what portion, if any, of natural gas we purchase from
producers that had been contractually dedicated for resale to
Targa. As of March 31, 2010, we had fixed contractual
commitments to provide Targa a total of 2,373,000
20
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 9 Commitments
and Contingencies (Continued)
thousand cubic feet (Mcf) of natural gas for
October 1, 2009 through December 31, 2010 and for each
of 2011, 2012 and 2013. As of March 31, 2010, we have
accrued $754,136 of our obligation due December 31, 2010.
Under the terms of the agreement, we are obligated to pay annual
fees ($1.00 per Mcf, $1.10 per Mcf, $1.15 per Mcf and $1.25 per
Mcf for 2010, 2011, 2012 and 2013, respectively) to the extent
our natural gas deliveries to Targa fall below the committed
quantity.
Regulatory
Compliance
In the ordinary course of business, we are subject to various
laws and regulations. In the opinion of our management,
compliance with existing laws and regulations will not
materially affect our financial position, results of operations
or cash flows.
Litigation
As a result of our Cantera acquisition in October 2007, we
acquired Cantera Gas Company LLC (Cantera Gas
Company, formerly CMS Field Services, Inc.
(CMSFS)). Cantera Gas Company is a party to a number
of legal proceedings alleging (i) false reporting of
natural gas prices by CMSFS and numerous other parties and
(ii) other related claims. The claims made in these
proceedings are based on events that occurred before Cantera
Resources, Inc. acquired CMSFS in June 2003 (the CMS
Acquisition). The amount of liability, if any, against
Cantera Gas Company is not reasonably estimable. Pursuant to the
CMS Acquisition purchase agreement, CMS Gas Transmission has
assumed responsibility for the defense of these claims, and
Cantera Gas Company is fully indemnified by CMS Gas Transmission
and its parent, CMS Enterprises Company, against any losses that
Cantera Gas Company may suffer as a result of these claims.
We may, from time to time, be involved in other litigation and
claims arising out of our operations in the normal course of
business.
Note 10 Supplemental
Disclosures to the Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Cash payments for interest, net of $495,000 and $1,163,000
capitalized in 2010 and 2009, respectively
|
|
$
|
14,966
|
|
|
$
|
15,061
|
|
Cash payments for federal and state income taxes
|
|
$
|
|
|
|
$
|
|
|
We incurred a change in liabilities for investing activities
that had not been paid as of March 31, 2010 and 2009 of
$2,407,000 and $7,711,000, respectively. Such amounts are not
included in the change in accounts payable and accrued
liabilities or with acquisitions, additions to property, plant
and equipment and intangible assets on the consolidated
statements of cash flows. As of March 31, 2010 and 2009, we
accrued $7,656,000 and $6,084,000, respectively, for capital
expenditures that had not been paid and, therefore, these
amounts are not included in investing activities for each
respective period presented.
Note 11 Financial
Instruments
We are exposed to market risks, including changes in commodity
prices and interest rates. We may use financial instruments such
as puts, calls, swaps and other financial instruments to
mitigate the effects of the identified risks. In general, we
attempt to hedge risks related to the variability of our future
cash flow and profitability resulting from changes in applicable
commodity prices or interest rates so that we can maintain cash
flows sufficient to meet debt service, required capital
expenditures, distribution objectives and similar requirements.
21
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 11 Financial
Instruments (Continued)
Commodity
Risk Hedging Program
NGL and natural gas prices are volatile and are impacted by
changes in fundamental supply and demand, as well as market
uncertainty and a variety of additional factors that are beyond
our control. Our profitability is directly affected by
prevailing commodity prices as a result of: (i) processing
or conditioning at our processing plants or third-party
processing plants and (ii) purchasing and selling volumes
of natural gas at index-related prices. In order to manage the
risks associated with natural gas and NGL prices, we engage in
risk management activities that take the form of commodity
derivative instruments. These activities are governed by our
risk management policy, which, subject to certain limitations,
allows our management to purchase options and enter into swaps
for crude oil, NGLs and natural gas in order to reduce our
exposure to a substantial adverse change in the prices of those
commodities. Our risk management policy prohibits the use of
derivative instruments for speculative purposes.
Our Risk Management Committee monitors and ensures compliance
with the risk management policy and consists of senior level
executives in the operations, finance and legal departments. The
Audit Committee of our Board of Directors monitors the
implementation of the policy and we have engaged an independent
firm to provide additional oversight. The risk management policy
provides that all derivative transactions must be executed by
our Chief Financial Officer and must be authorized in advance of
execution by our Chief Executive Officer. The policy requires
derivative transactions to take place either on the New York
Mercantile Exchange (NYMEX) through a clearing member firm or
with
over-the-counter
counterparties with investment grade ratings from both
Moodys Investors Service and Standard &
Poors Ratings Services with complete industry standard
contractual documentation. Under this documentation, the payment
obligations in connection with our swap transactions are secured
by a first priority lien in the collateral securing our senior
secured indebtedness that ranks equal in right of payment with
liens granted in favor of our senior secured lenders. As long as
this first priority lien is in effect, we will have no
obligation to post cash, letters of credit or other additional
collateral to secure these hedges at any time, even if our
counterpartys exposure to our credit increases over the
term of the hedge as a result of higher commodity prices or
because there has been a change in our creditworthiness.
Financial instruments that we acquire pursuant to our risk
management policy are generally designated as cash flow hedges
under ASC 815 and are recorded on our consolidated balance
sheets at fair value. For derivatives designated as cash flow
hedges, we recognize the effective portion of changes in fair
value as other comprehensive income (OCI) and
reclassify them to revenue within the consolidated statements of
operations as the underlying transactions impact earnings. For
derivatives not designated as cash flow hedges, we recognize
changes in fair value as a gain or loss in our consolidated
statements of operations. These financial instruments serve the
same risk management purpose whether designated as a cash flow
hedge or not.
We assess, both at the inception of the hedge and on an ongoing
basis, whether the derivatives are effective in hedging the
variability of forecasted cash flows of underlying hedged items.
If it is determined that a derivative is not effective as a
hedge or that it has ceased to be an effective hedge due to the
loss of correlation between the hedging instrument and the
underlying hedged item or it becomes probable that the original
forecasted transaction will not occur, we discontinue hedge
accounting and subsequent changes in the derivative fair value
are immediately recognized as a gain or loss (increase or
decrease in revenue) in our consolidated statements of
operations.
As of March 31, 2010, we estimated that $2,344,000 of OCI
will be reclassified as a decrease to earnings in the next
12 months as a result of monthly physical settlements of
crude oil, NGLs and natural gas.
22
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 11 Financial
Instruments (Continued)
The following tables summarize our commodity hedge portfolio as
of March 31, 2010 (all hedges are settled monthly):
Purchased
Houston Ship Channel Index Natural Gas Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Call Spread
|
|
|
Call
|
|
|
|
Call Strike
|
|
|
|
|
|
|
|
|
|
|
|
|
(Per MMBtu)
|
|
|
Call Volumes
|
|
|
Strike
|
|
|
|
|
|
|
Bought
|
|
|
Sold
|
|
|
(MMBtu/d)
|
|
|
(Per MMBtu)
|
|
|
Volume (MMBtu/d)
|
|
|
2010
|
|
$
|
7.3500
|
|
|
$
|
10.0000
|
|
|
|
7,100
|
|
|
$
|
10.0000
|
|
|
|
10,000
|
|
2011
|
|
$
|
6.9500
|
|
|
$
|
10.0000
|
|
|
|
7,100
|
|
|
$
|
10.0000
|
|
|
|
10,000
|
|
Purchased
Houston Ship Channel Index Natural Gas Basis Swap
|
|
|
|
|
|
|
|
|
|
|
Price
|
|
|
Volume
|
|
|
|
(per MMBtu)
|
|
|
(MMBtu/d)
|
|
|
2010(1)
|
|
$
|
0.0450
|
|
|
|
10,000
|
|
|
|
|
(1) |
|
Instrument is not designated as a cash flow hedge under hedge
accounting. |
Sold
CenterPoint East Index Natural Gas Basis Swap
|
|
|
|
|
|
|
|
|
|
|
Price
|
|
|
Volume
|
|
|
|
(per MMBtu)
|
|
|
(MMBtu/d)
|
|
|
2010(1)
|
|
$
|
0.2300
|
|
|
|
10,000
|
|
|
|
|
(1) |
|
Instrument is not designated as a cash flow hedge under hedge
accounting. |
Purchased
Mt. Belvieu Purity Ethane Puts and Entered into Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put
|
|
|
Swap
|
|
|
|
Strike
|
|
|
Volumes
|
|
|
Price
|
|
|
Volumes
|
|
|
|
(Per gallon)
|
|
|
(Bbls/d)
|
|
|
(Per gallon)
|
|
|
(Bbls/d)
|
|
|
2010
|
|
$
|
0.5550
|
|
|
|
1,600
|
|
|
$
|
0.5700
|
|
|
|
500
|
|
2011
|
|
$
|
0.5300
|
|
|
|
1,700
|
|
|
$
|
0.5450
|
|
|
|
500
|
|
2011
|
|
$
|
0.5300
|
|
|
|
500
|
|
|
|
|
|
|
|
|
|
2011
|
|
$
|
0.6200
|
|
|
|
500
|
|
|
|
|
|
|
|
|
|
2012
|
|
$
|
0.5900
|
|
|
|
1,000
|
|
|
|
|
|
|
|
|
|
Purchased
Mt. Belvieu TET Propane Puts and Entered into Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put
|
|
|
Swap
|
|
|
|
Strike
|
|
|
Volumes
|
|
|
Price
|
|
|
Volumes
|
|
|
|
(Per gallon)
|
|
|
(Bbls/d)
|
|
|
(Per gallon)
|
|
|
(Bbls/d)
|
|
|
2010
|
|
$
|
0.8500
|
|
|
|
1,100
|
|
|
|
|
|
|
|
|
|
2010
|
|
$
|
0.9460
|
|
|
|
700
|
|
|
$
|
0.9925
|
|
|
|
700
|
|
2011
|
|
$
|
0.8265
|
|
|
|
1,100
|
|
|
|
|
|
|
|
|
|
2011
|
|
$
|
0.9340
|
|
|
|
700
|
|
|
$
|
0.9750
|
|
|
|
700
|
|
2011
|
|
$
|
1.3300
|
|
|
|
900
|
|
|
|
|
|
|
|
|
|
2012
|
|
$
|
1.1500
|
|
|
|
700
|
|
|
|
|
|
|
|
|
|
23
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 11 Financial
Instruments (Continued)
Purchased
Mt. Belvieu TET Propane Put Spread Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put Spread
|
|
|
|
Strike
|
|
|
Volumes
|
|
|
|
(Per gallon)
|
|
|
(Bbls/d)
|
|
|
|
Bought
|
|
|
Sold
|
|
|
|
|
|
2010
|
|
$
|
1.4900
|
|
|
$
|
0.8500
|
|
|
|
1,100
|
|
2010
|
|
$
|
1.4900
|
|
|
$
|
0.9460
|
|
|
|
700
|
|
Purchased
Mt. Belvieu Non-TET Isobutane Puts and Entered into
Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put
|
|
|
Swap
|
|
|
|
Strike
|
|
|
Volumes
|
|
|
Price
|
|
|
Volumes
|
|
|
|
(Per gallon)
|
|
|
(Bbls/d)
|
|
|
(Per gallon)
|
|
|
(Bbls/d)
|
|
|
2010
|
|
$
|
1.0350
|
|
|
|
300
|
|
|
|
|
|
|
|
|
|
2010
|
|
$
|
1.1145
|
|
|
|
100
|
|
|
$
|
1.2025
|
|
|
|
100
|
|
2011
|
|
$
|
1.0205
|
|
|
|
300
|
|
|
|
|
|
|
|
|
|
2011
|
|
$
|
1.1100
|
|
|
|
100
|
|
|
$
|
1.1800
|
|
|
|
100
|
|
2011
|
|
$
|
1.7100
|
|
|
|
200
|
|
|
|
|
|
|
|
|
|
2012
|
|
$
|
1.3900
|
|
|
|
300
|
|
|
|
|
|
|
|
|
|
Purchased
Mt. Belvieu Non-TET Isobutane Put Spread Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put Spread
|
|
|
|
Strike
|
|
|
|
|
|
|
(Per gallon)
|
|
|
Volumes
|
|
|
|
Bought
|
|
|
Sold
|
|
|
(Bbls/d)
|
|
|
2010
|
|
$
|
1.8900
|
|
|
$
|
1.1145
|
|
|
|
100
|
|
2010
|
|
$
|
1.8900
|
|
|
$
|
1.0350
|
|
|
|
300
|
|
Purchased
Mt. Belvieu Non-TET Normal Butane Puts and Entered into
Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put
|
|
|
Swap
|
|
|
|
Strike
|
|
|
Volumes
|
|
|
Price
|
|
|
Volumes
|
|
|
|
(Per gallon)
|
|
|
(Bbls/d)
|
|
|
(Per gallon)
|
|
|
(Bbls/d)
|
|
|
2010
|
|
$
|
1.0300
|
|
|
|
300
|
|
|
|
|
|
|
|
|
|
2010
|
|
$
|
1.1000
|
|
|
|
200
|
|
|
$
|
1.1850
|
|
|
|
200
|
|
2011
|
|
$
|
1.0205
|
|
|
|
300
|
|
|
|
|
|
|
|
|
|
2011
|
|
$
|
1.0850
|
|
|
|
200
|
|
|
$
|
1.1700
|
|
|
|
200
|
|
2011
|
|
$
|
1.7100
|
|
|
|
350
|
|
|
|
|
|
|
|
|
|
2012
|
|
$
|
1.3600
|
|
|
|
350
|
|
|
|
|
|
|
|
|
|
Purchased
Mt. Belvieu Non-TET Normal Butane Put Spread Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put Spread
|
|
|
|
Strike
|
|
|
Volumes
|
|
|
|
(Per gallon)
|
|
|
(Bbls/d)
|
|
|
|
Bought
|
|
|
Sold
|
|
|
|
|
|
2010
|
|
$
|
1.8800
|
|
|
$
|
1.1000
|
|
|
|
200
|
|
2010
|
|
$
|
1.8800
|
|
|
$
|
1.0300
|
|
|
|
300
|
|
24
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 11 Financial
Instruments (Continued)
Purchased
Mt. Belvieu Non-TET Natural Gasoline Puts
|
|
|
|
|
|
|
|
|
|
|
Put
|
|
|
|
Strike
|
|
|
Volumes
|
|
|
|
(Per gallon)
|
|
|
(Bbls/d)
|
|
|
2010
|
|
$
|
1.4080
|
|
|
|
300
|
|
2011
|
|
$
|
1.4100
|
|
|
|
300
|
|
Purchased
Mt. Belvieu Non-TET Natural Gasoline Put Spread
Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put Spread
|
|
|
|
Strike
|
|
|
Volumes
|
|
|
|
(Per gallon)
|
|
|
(Bbls/d)
|
|
|
|
Bought
|
|
|
Sold
|
|
|
|
|
|
2010
|
|
$
|
2.5400
|
|
|
$
|
1.4080
|
|
|
|
300
|
|
Purchased
WTI Crude Oil Puts
|
|
|
|
|
|
|
|
|
|
|
Put
|
|
|
|
Strike
|
|
|
Volumes
|
|
|
|
(Per barrel)
|
|
|
(Bbls/d)
|
|
|
2010
|
|
$
|
55.00
|
|
|
|
1,000
|
|
2010
|
|
$
|
60.00
|
|
|
|
400
|
|
2011(1)
|
|
$
|
55.00
|
|
|
|
1,000
|
|
2011
|
|
$
|
60.00
|
|
|
|
400
|
|
2011
|
|
$
|
77.00
|
|
|
|
700
|
|
2011
|
|
$
|
79.00
|
|
|
|
400
|
|
2011(2)
|
|
$
|
85.00
|
|
|
|
200
|
|
2012
|
|
$
|
79.00
|
|
|
|
300
|
|
2012(2)
|
|
$
|
83.00
|
|
|
|
350
|
|
2012(2)
|
|
$
|
85.00
|
|
|
|
350
|
|
|
|
|
(1) |
|
Instrument is not designated as a cash flow hedge under hedge
accounting. |
|
(2) |
|
Instrument purchased April 2010. |
Purchased
WTI Crude Oil Put Spread Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put Spread
|
|
|
|
Strike
|
|
|
|
|
|
|
(Per barrel)
|
|
|
Volumes
|
|
|
|
Bought
|
|
|
Sold
|
|
|
(Bbls/d)
|
|
|
2010
|
|
$
|
118.00
|
|
|
$
|
55.00
|
|
|
|
1,000
|
|
2010
|
|
$
|
118.00
|
|
|
$
|
60.00
|
|
|
|
400
|
|
Interest
Rate Risk Hedging Program
Our interest rate exposure results from variable rate borrowings
under our Credit Facility. We manage a portion of our interest
rate exposure using interest rate swaps, which allow us to
convert a portion of our variable rate debt into fixed rate
debt. As of March 31, 2010, we hold a notional amount of
$145.0 million in interest rate swaps with
25
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 11 Financial
Instruments (Continued)
an average fixed rate of 4.44% that mature between July 2010 and
October 2012. As of March 31, 2010, our interest rate swaps
are not designated as cash flow hedges.
As of March 31, 2010, we estimate that $442,000 of OCI will
be reclassified as an increase to earnings in the next
12 months as the underlying instruments expire.
ASC
820 Fair Value Measurement and ASC 815 Disclosures about
Derivative Instruments and Hedging Activities
We recognize the fair value of our assets and liabilities that
require periodic re-measurement as necessary based upon the
requirements of ASC 820. This standard defines fair value,
expands disclosure requirements with respect to fair value and
specifies a hierarchy of valuation techniques based on whether
the inputs to those valuation techniques are observable or
unobservable. Inputs are the assumptions that a
market participant would use in valuing the asset or liability.
Observable inputs reflect market data obtained from independent
sources, while unobservable inputs reflect our market
assumptions. The three levels of the fair value hierarchy
established by ASC 820 are as follows:
|
|
|
|
|
Level 1 Unadjusted quoted prices in active
markets that are accessible at the measurement date for
identical, unrestricted assets or liabilities;
|
|
|
|
Level 2 Quoted prices in markets that are not
considered to be active or financial instruments for which all
significant inputs are observable, either directly or
indirectly; and
|
|
|
|
Level 3 Prices or valuations that require
inputs that are both significant to the fair value measurement
and unobservable. These inputs may be used with internally
developed methodologies that result in managements best
estimate of fair value.
|
At each balance sheet date, we perform an analysis of all
instruments subject to ASC 820 and include in Level 3
all of those for which fair value is based on significant
unobservable inputs.
26
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 11 Financial
Instruments (Continued)
The following table sets forth by level within the fair value
hierarchy our financial assets and liabilities that were
accounted for at fair value on a recurring basis as of
March 31, 2010 and December 31, 2009. As required by
ASC 820, assets and liabilities are classified in their
entirety based on the lowest level of input that is significant
to the fair value measurement. Managements assessment of
the significance of a particular input to the fair value
measurement requires judgment and may affect the valuation of
fair value of assets and liabilities and their placement with
the fair value hierarchy levels.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements on Hedging
Instruments(a)
|
|
|
|
March 31, 2010
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
Designated(b)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
196
|
|
|
$
|
196
|
|
Long-term
Designated(c)
|
|
|
|
|
|
|
|
|
|
|
526
|
|
|
|
526
|
|
Natural Gas Liquids:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
Designated(b)
|
|
|
|
|
|
|
|
|
|
|
16,724
|
|
|
|
16,724
|
|
Long-term
Designated(c)
|
|
|
|
|
|
|
|
|
|
|
13,252
|
|
|
|
13,252
|
|
Crude Oil:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
Designated(b)
|
|
|
|
|
|
|
|
|
|
|
13,414
|
|
|
|
13,414
|
|
Long-term
Designated(c)
|
|
|
|
|
|
|
|
|
|
|
3,123
|
|
|
|
3,123
|
|
Long-term Not
designated(c)
|
|
|
|
|
|
|
|
|
|
|
266
|
|
|
|
266
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
|
$
|
47,501
|
|
|
$
|
47,501
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term Not
designated(d)
|
|
$
|
|
|
|
$
|
156
|
|
|
$
|
|
|
|
$
|
156
|
|
Natural Gas Liquids:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
Designated(d)
|
|
|
|
|
|
|
|
|
|
|
2,898
|
|
|
|
2,898
|
|
Long-term
Designated(e)
|
|
|
|
|
|
|
|
|
|
|
1,580
|
|
|
|
1,580
|
|
Interest Rate:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term Not
designated(d)
|
|
|
|
|
|
|
4,370
|
|
|
|
|
|
|
|
4,370
|
|
Long-term Not
designated(e)
|
|
|
|
|
|
|
3,722
|
|
|
|
|
|
|
|
3,722
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
8,248
|
|
|
$
|
4,478
|
|
|
$
|
12,726
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total designated assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
42,757
|
|
|
$
|
42,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total not designated (liabilities)/assets
|
|
$
|
|
|
|
$
|
(8,248
|
)
|
|
$
|
266
|
|
|
$
|
(7,982
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Instruments re-measured on a
recurring basis.
|
|
(b)
|
|
Included on the consolidated
balance sheets as a current asset under the heading of
Risk management assets.
|
|
(c)
|
|
Included on the consolidated
balance sheets as a noncurrent asset under the heading of
Risk management assets.
|
|
(d)
|
|
Included on the consolidated
balance sheets as a current liability under the heading of
Risk management liabilities.
|
|
(e)
|
|
Included on the consolidated
balance sheets as a noncurrent liability under the heading of
Risk management and other noncurrent liabilities.
|
27
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 11 Financial
Instruments (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements on Hedging
Instruments(a)
|
|
|
|
December 31, 2009
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
Designated(b)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
36,588
|
|
|
$
|
36,588
|
|
Short-term Not
designated(b)
|
|
|
|
|
|
|
27
|
|
|
|
|
|
|
|
27
|
|
Long-term
Designated(c)
|
|
|
|
|
|
|
|
|
|
|
14,805
|
|
|
|
14,805
|
|
Long-term Not
designated(c)
|
|
|
|
|
|
|
|
|
|
|
576
|
|
|
|
576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
27
|
|
|
$
|
51,969
|
|
|
$
|
51,996
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
Designated(d)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4,763
|
|
|
$
|
4,763
|
|
Long-term
Designated(e)
|
|
|
|
|
|
|
|
|
|
|
4,600
|
|
|
|
4,600
|
|
Interest rate derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term Not
designated(d)
|
|
|
|
|
|
|
4,909
|
|
|
|
|
|
|
|
4,909
|
|
Long-term Not
designated(e)
|
|
|
|
|
|
|
3,238
|
|
|
|
|
|
|
|
3,238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
8,147
|
|
|
$
|
9,363
|
|
|
$
|
17,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total designated assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
42,030
|
|
|
$
|
42,030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total not designated (liabilities)/assets
|
|
$
|
|
|
|
$
|
(8,120
|
)
|
|
$
|
576
|
|
|
$
|
(7,544
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Instruments re-measured on a
recurring basis.
|
|
(b)
|
|
Included on the consolidated
balance sheets as a current asset under the heading of
Risk management assets.
|
|
(c)
|
|
Included on the consolidated
balance sheets as a noncurrent asset under the heading of
Risk management assets.
|
|
(d)
|
|
Included on the consolidated
balance sheets as a current liability under the heading of
Risk management liabilities.
|
|
(e)
|
|
Included on the consolidated
balance sheets as a noncurrent liability under the heading of
Risk management and other noncurrent liabilities.
|
We use the income approach incorporating market-based inputs in
determining fair value for our derivative contracts.
Valuation of our Level 2 derivative contracts are based on
observable market prices
(1-month or
3-month
LIBOR interest rate curves or CenterPoint East and Houston Ship
Channel market curves) incorporating discount rates and credit
risk.
Valuation of our Level 3 derivative contracts incorporates
the use of valuation models using significant unobservable
inputs. To the extent certain model inputs are observable
(prices of WTI Crude, Mt. Belvieu NGLs and Houston Ship Channel
natural gas), we include observable market price and volatility
data as inputs to our valuation model in addition to
incorporating discount rates and credit risk. For those input
parameters that are not readily available (implied volatilities
for Mt. Belvieu NGL prices or prices for illiquid periods of
price curves), the modeling methodology incorporates available
market information to generate these inputs through techniques
such as regression based extrapolation.
28
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 11 Financial
Instruments (Continued)
The following table provides a reconciliation of changes in the
fair value of derivatives classified as Level 3 in the fair
value hierarchy (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2010
|
|
|
|
Natural Gas
|
|
|
Natural Gas Liquids
|
|
|
Crude Oil
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Assets balance, beginning of period
|
|
$
|
2,752
|
|
|
$
|
15,641
|
|
|
$
|
24,213
|
|
|
$
|
42,606
|
|
Total gains or losses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash amortization of option premium
|
|
|
(1,456
|
)
|
|
|
(4,057
|
)
|
|
|
(2,465
|
)
|
|
|
(7,978
|
)
|
Other amounts included in earnings
|
|
|
|
|
|
|
2,066
|
|
|
|
4,720
|
|
|
|
6,786
|
|
Included in accumulated other comprehensive loss
|
|
|
(572
|
)
|
|
|
6,583
|
|
|
|
(4,723
|
)
|
|
|
1,288
|
|
Purchases
|
|
|
|
|
|
|
7,381
|
|
|
|
|
|
|
|
7,381
|
|
Settlements
|
|
|
|
|
|
|
(2,116
|
)
|
|
|
(4,940
|
)
|
|
|
(7,056
|
)
|
Transfers in and/or out of Level 3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset balance, end of year
|
|
$
|
724
|
|
|
$
|
25,498
|
|
|
$
|
16,805
|
|
|
$
|
43,027
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in unrealized losses (income) included in earnings
related to instruments still held as of the end of the period
|
|
$
|
|
|
|
$
|
(56
|
)
|
|
$
|
(438
|
)
|
|
$
|
(494
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31, 2009
|
|
|
|
(In thousands)
|
|
|
Assets balance, beginning of year
|
|
$
|
152,677
|
|
Total gains or losses:
|
|
|
|
|
Non-cash amortization of option premium
|
|
|
(9,188
|
)
|
Other amounts included in earnings
|
|
|
25,285
|
|
Included in accumulated other comprehensive loss
|
|
|
(7,502
|
)
|
Purchases
|
|
|
|
|
Settlements
|
|
|
(25,120
|
)
|
Transfers in and/or out of Level 3
|
|
|
|
|
|
|
|
|
|
Asset balance, end of year
|
|
$
|
136,152
|
|
|
|
|
|
|
Change in unrealized losses (income) included in earnings
related to instruments still held as of the end of the year
|
|
$
|
56
|
|
|
|
|
|
|
Unrealized and realized gains and losses for Level 3
recurring items recorded in earnings are included in revenue on
the consolidated statements of operations. The effective portion
of unrealized gains and losses relating to cash flow hedges are
included in accumulated other comprehensive loss on the
consolidated balance sheet and statement of members
capital and comprehensive loss.
Transfers in
and/or out
of Level 2 or Level 3 represent existing assets or
liabilities where inputs to the valuation became less observable
or assets and liabilities that were previously classified as a
lower level for which the lowest significant input became
observable during the period. There were no transfers in or out
of Level 2 or Level 3 during the period.
29
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 11 Financial
Instruments (Continued)
We have not entered into any derivative transactions containing
credit risk related contingent features as of March 31,
2010.
The following table presents derivatives that are designated as
cash flow hedges:
The
Effect of Derivative Instruments on the Statements of
Operations
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) Recognized
|
|
|
|
|
|
|
|
|
|
|
|
in Income on
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
|
|
|
|
|
|
Amount of Gain
|
|
|
Amount of Gain
|
|
|
(Ineffective
|
|
|
|
Derivatives in ASC
|
|
(Loss) Recognized
|
|
|
(Loss) Reclassified
|
|
|
Portion and Amount
|
|
|
|
815 Cash Flow
|
|
in OCI on
|
|
|
from Accumulated
|
|
|
Excluded from
|
|
|
|
Hedging
|
|
Derivatives
|
|
|
OCI into Income
|
|
|
Effectiveness
|
|
|
Statements of Operations
|
Relationships
|
|
(Effective Portion)
|
|
|
(Effective Portion)
|
|
|
Testing)
|
|
|
Location
|
|
Three Months Ended March 31, 2010
|
Natural gas
|
|
$
|
(2,013
|
)
|
|
$
|
(1,439
|
)
|
|
$
|
|
|
|
Natural gas sales
|
Natural gas liquids
|
|
|
4,930
|
|
|
|
(1,654
|
)
|
|
|
(56
|
)
|
|
Natural gas liquids sales
|
Crude oil
|
|
|
(2,351
|
)
|
|
|
2,370
|
|
|
|
25
|
|
|
Condensate and other
|
Interest rate swaps
|
|
|
|
|
|
|
(132
|
)
|
|
|
|
|
|
Interest and other financing costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
566
|
|
|
$
|
(855
|
)
|
|
$
|
(31
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009
|
Natural gas
|
|
$
|
255
|
|
|
$
|
(766
|
)
|
|
$
|
|
|
|
Natural gas sales
|
Natural gas liquids
|
|
|
(3,534
|
)
|
|
|
11,494
|
|
|
|
(16
|
)
|
|
Natural gas liquids sales
|
Crude oil
|
|
|
(4,223
|
)
|
|
|
4,049
|
|
|
|
123
|
|
|
Condensate and other
|
Interest rate swaps
|
|
|
(181
|
)
|
|
|
(81
|
)
|
|
|
|
|
|
Interest and other financing costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(7,683
|
)
|
|
$
|
14,696
|
|
|
$
|
107
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 11 Financial
Instruments (Continued)
The following table presents derivatives that are not designated
as cash flow hedges:
The
Effect of Derivative Instruments on the Statements of
Operations
(In thousands)
|
|
|
|
|
|
|
Derivatives Not Designated as
|
|
Amount of Gain
|
|
|
|
Hedging Instruments
|
|
(Loss) Recognized
|
|
|
Statement of Operations
|
Under ASC 820
|
|
in Income on Derivative
|
|
|
Location
|
|
Three months ended March 31, 2010
|
Natural gas
|
|
$
|
(227
|
)
|
|
Natural gas sales
|
Crude oil
|
|
|
(306
|
)
|
|
Condensate and other
|
Interest rate swaps
|
|
|
(1,466
|
)
|
|
Interest and other financing costs
|
|
|
|
|
|
|
|
Total
|
|
$
|
(1,999
|
)
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2009
|
Natural gas liquids
|
|
$
|
56
|
|
|
Natural gas liquids sales
|
Interest rate swaps
|
|
|
75
|
|
|
Interest and other financing costs
|
|
|
|
|
|
|
|
Total
|
|
$
|
131
|
|
|
|
|
|
|
|
|
|
|
Note 12 Fair
Value of Financial Instruments
Amounts reflected in our consolidated balance sheets as of
March 31, 2010 for cash and cash equivalents approximate
fair value. The fair value of our Credit Facility has been
estimated based on similar debt transactions that occurred
during the three months ended March 31, 2010. Estimates of
the fair value of our Senior Notes are based on market
information as of March 31, 2010. A summary of the fair
value and carrying value of the financial instruments is shown
in the table below.
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010
|
|
|
|
Carrying
|
|
|
Estimated
|
|
|
|
Value
|
|
|
Fair Value
|
|
|
|
(In thousands)
|
|
|
Cash and cash equivalents
|
|
$
|
54,148
|
|
|
$
|
54,148
|
|
Credit Facility
|
|
|
135,000
|
|
|
|
131,971
|
|
2016 Notes
|
|
|
332,665
|
|
|
|
337,655
|
|
2018 Notes
|
|
|
249,525
|
|
|
|
249,525
|
|
31
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 13 Discontinued
Operations
Effective October 1, 2009, we sold our crude oil pipeline
and related assets, and as a result, we have classified the
results of operations and financial position of our crude oil
pipeline as discontinued operations for all periods
presented. In the fourth quarter of 2009, we recognized a gain
on the sale of the crude oil pipeline system of approximately
$0.9 million. Selected financial data for the crude oil
pipeline and related assets are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Crude oil sales
|
|
$
|
|
|
|
$
|
15,338
|
|
Cost of crude oil purchases
|
|
|
|
|
|
|
14,428
|
|
Income from discontinued operations before taxes
|
|
$
|
|
|
|
$
|
561
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from discontinued operations
|
|
$
|
|
|
|
$
|
561
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 14
|
Segment
Information
|
We manage our business and analyze and report our results of
operations on a segment basis. Our operations are divided into
the following three segments for both internal and external
reporting and analysis:
|
|
|
|
|
Oklahoma, which includes midstream natural gas services in
central and east Oklahoma, including gathering of natural gas
and related services such as compression, dehydration, treating,
processing and nitrogen rejection. This segment includes our
equity investment in Southern Dome and, through
September 30, 2009, included a crude oil pipeline.
|
|
|
|
Texas, which includes midstream natural gas services in south
and north Texas, including gathering and intrastate transmission
of natural gas, and related services such as compression,
dehydration, treating, conditioning or processing and marketing.
Our Texas segment also provides NGL fractionation and
transportation. Our Texas segment includes our Louisiana
processing assets and our equity investment in Webb Duval.
|
|
|
|
Rocky Mountains, which includes natural gas gathering and
treating and compressor rental services in Wyoming. Our Rocky
Mountains segment includes our equity investments in Bighorn and
Fort Union.
|
The amounts indicated below as Corporate and other
relate to our risk management activities, intersegment
eliminations and other activities we perform or assets we hold
that have not been allocated to any of our reporting segments.
We evaluate segment performance based on segment gross margin
before depreciation, amortization and impairment. All of our
revenue is derived from, and all of our assets and operations
are located in Oklahoma, Texas, Wyoming and Louisiana in the
United States. Operating and maintenance expenses and general
and administrative expenses incurred at corporate and other are
allocated to Oklahoma, Texas and Rocky Mountains based on actual
expenses directly attributable to each segment or an allocation
based on activity, as appropriate. We use the same accounting
methods and allocations in the preparation of our segment
information as we use in our consolidated reporting.
32
COPANO
ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO
UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 14
Segment Information (Continued)
Summarized financial information concerning our reportable
segments is shown in the following table (in thousands). Prior
year information has been restated to conform to the current
year presentation of our segment information.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rocky
|
|
|
Total
|
|
|
Corporate
|
|
|
|
|
|
|
Oklahoma(a)
|
|
|
Texas
|
|
|
Mountains
|
|
|
Segments
|
|
|
and Other
|
|
|
Consolidated
|
|
|
Three Months Ended March 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment gross margin
|
|
$
|
24,275
|
|
|
$
|
27,165
|
|
|
$
|
1,103
|
|
|
$
|
52,543
|
|
|
$
|
(1,418
|
)
|
|
$
|
51,125
|
|
Operations and maintenance expenses
|
|
|
5,433
|
|
|
|
6,569
|
|
|
|
101
|
|
|
|
12,103
|
|
|
|
|
|
|
|
12,103
|
|
Depreciation and amortization
|
|
|
8,415
|
|
|
|
5,585
|
|
|
|
766
|
|
|
|
14,766
|
|
|
|
435
|
|
|
|
15,201
|
|
General and administrative expenses
|
|
|
2,287
|
|
|
|
2,410
|
|
|
|
537
|
|
|
|
5,234
|
|
|
|
5,308
|
|
|
|
10,542
|
|
Taxes other than income
|
|
|
499
|
|
|
|
663
|
|
|
|
|
|
|
|
1,162
|
|
|
|
|
|
|
|
1,162
|
|
Equity in (earnings) loss from unconsolidated affiliates
|
|
|
(954
|
)
|
|
|
65
|
|
|
|
(906
|
)
|
|
|
(1,795
|
)
|
|
|
|
|
|
|
(1,795
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
8,595
|
|
|
$
|
11,873
|
|
|
$
|
605
|
|
|
$
|
21,073
|
|
|
$
|
(7,161
|
)
|
|
$
|
13,912
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
59,481
|
|
|
$
|
61,811
|
|
|
$
|
604
|
|
|
$
|
121,896
|
|
|
$
|
(1,680
|
)
|
|
$
|
120,216
|
|
Natural gas liquids sales
|
|
|
61,023
|
|
|
|
60,286
|
|
|
|
|
|
|
|
121,309
|
|
|
|
(1,991
|
)
|
|
|
119,318
|
|
Transportation, compression and processing fees
|
|
|
1,243
|
|
|
|
7,337
|
|
|
|
4,534
|
|
|
|
13,114
|
|
|
|
|
|
|
|
13,114
|
|
Condensate and other
|
|
|
8,956
|
|
|
|
2,392
|
|
|
|
417
|
|
|
|
11,765
|
|
|
|
2,253
|
|
|
|
14,018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to external customers
|
|
$
|
130,703
|
|
|
$
|
131,826
|
|
|
$
|
5,555
|
|
|
$
|
268,084
|
|
|
$
|
(1,418
|
)
|
|
$
|
266,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment sales
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Interest and other financing costs
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
14,945
|
|
|
$
|
14,945
|
|
Segment assets
|
|
$
|
719,306
|
|
|
$
|
453,612
|
|
|
$
|
686,564
|
|
|
$
|
1,859,482
|
|
|
$
|
10,616
|
|
|
$
|
1,870,098
|
|
Three Months Ended March 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment gross margin
|
|
$
|
14,300
|
|
|
$
|
20,580
|
|
|
$
|
799
|
|
|
$
|
35,679
|
|
|
$
|
16,096
|
|
|
$
|
51,775
|
|
Operations and maintenance expenses
|
|
|
5,616
|
|
|
|
7,054
|
|
|
|
2
|
|
|
|
12,672
|
|
|
|
|
|
|
|
12,672
|
|
Depreciation and amortization
|
|
|
7,754
|
|
|
|
4,347
|
|
|
|
671
|
|
|
|
12,772
|
|
|
|
333
|
|
|
|
13,105
|
|
General and administrative expenses
|
|
|
1,971
|
|
|
|
2,251
|
|
|
|
749
|
|
|
|
4,971
|
|
|
|
5,754
|
|
|
|
10,725
|
|
Taxes other than income
|
|
|
404
|
|
|
|
380
|
|
|
|
2
|
|
|
|
786
|
|
|
|
|
|
|
|
786
|
|
Equity in (earnings) loss from unconsolidated affiliates
|
|
|
(217
|
)
|
|
|
24
|
|
|
|
(1,291
|
)
|
|
|
(1,484
|
)
|
|
|
|
|
|
|
(1,484
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
$
|
(1,228
|
)
|
|
$
|
6,524
|
|
|
$
|
666
|
|
|
$
|
5,962
|
|
|
$
|
10,009
|
|
|
$
|
15,971
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
40,868
|
|
|
$
|
51,754
|
|
|
$
|
2,737
|
|
|
$
|
95,359
|
|
|
$
|
(380
|
)
|
|
$
|
94,979
|
|
Natural gas liquids sales
|
|
|
33,066
|
|
|
|
36,180
|
|
|
|
|
|
|
|
69,246
|
|
|
|
11,585
|
|
|
|
80,831
|
|
Transportation, compression and processing fees
|
|
|
1,787
|
|
|
|
7,595
|
|
|
|
5,617
|
|
|
|
14,999
|
|
|
|
|
|
|
|
14,999
|
|
Condensate and other
|
|
|
4,549
|
|
|
|
829
|
|
|
|
|
|
|
|
5,378
|
|
|
|
4,891
|
|
|
|
10,269
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to external customers
|
|
$
|
80,270
|
|
|
$
|
96,358
|
|
|
$
|
8,354
|
|
|
$
|
184,982
|
|
|
$
|
16,096
|
|
|
$
|
201,078
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment sales
|
|
$
|
(290
|
)
|
|
$
|
290
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Interest and other financing costs
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
14,448
|
|
|
$
|
14,448
|
|
|
|
|
(a)
|
|
All information excludes the
results of discontinued operations for the sale of the crude oil
pipeline and related assets (Note 13) except for the
information related to intersegment sales and interest and other
financing costs.
|
33
|
|
Item 2.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
|
You should read the following discussion of our financial
condition and results of operations in conjunction with the
unaudited consolidated financial statements and notes thereto
included in Item 1 of this report, as well as Item 7,
Managements Discussion and Analysis of Financial
Condition and Results of Operations, and the audited
financial statements included in Item 8 of our Annual
Report on
Form 10-K
and Amendment No. 1 for the year ended December 31,
2009 (our 2009
10-K).
As generally used in the energy industry and in this report, the
following terms have the following meanings:
|
|
|
/d:
|
|
Per day
|
Bcf:
|
|
One billion cubic feet
|
Btu:
|
|
One British thermal unit
|
Lean Gas:
|
|
Natural gas that is low in NGL content
|
MMBtu:
|
|
One million British thermal units
|
Mcf:
|
|
One thousand cubic feet
|
MMcf:
|
|
One million cubic feet
|
NGLs:
|
|
Natural gas liquids, which consist primarily of ethane,
propane, isobutane, normal butane, natural gasoline and
stabilized condensate
|
Residue gas:
|
|
The pipeline quality natural gas remaining after natural gas
is processed
|
Rich gas:
|
|
Natural gas that is high in NGL content
|
Throughput:
|
|
The volume of natural gas or NGLs transported or passing
through a pipeline, plant, terminal or other facility
|
Overview
Through our subsidiaries, we own and operate natural gas
gathering and intrastate transmission pipeline assets, natural
gas processing and fractionation facilities and NGL pipelines.
We operate in Oklahoma, Texas, Wyoming and Louisiana. We manage
our business and analyze and report our results of operations on
a segment basis. Our operations are divided into three operating
segments: Oklahoma, Texas and Rocky Mountains.
|
|
|
|
|
Our Oklahoma segment provides midstream natural gas services in
central and east Oklahoma, including gathering of natural gas
and related services such as compression, dehydration, treating,
processing and nitrogen rejection. This segment includes our
equity investment in Southern Dome, and through September 2009,
included a crude oil pipeline.
|
|
|
|
Our Texas segment provides midstream natural gas services in
south and north Texas, including gathering and intrastate
transmission of natural gas, and related services such as
compression, dehydration, treating, conditioning or processing
and marketing. Our Texas segment also provides NGL fractionation
and transportation through our Houston Central plant and our NGL
pipelines. In addition, our Texas segment includes a processing
plant located in southwest Louisiana and our equity investment
in Webb Duval.
|
|
|
|
Our Rocky Mountains segment provides midstream natural gas
services in the Powder River Basin of Wyoming, including
gathering and treating of natural gas and compressor rental
services. This segment also includes our equity investments in
Bighorn and Fort Union.
|
Corporate and other relate to our risk management activities,
intersegment eliminations and other activities we perform or
assets we hold that have not been allocated to any of our
reporting segments.
Recent
Developments
Commencement of fractionation activities. In
April 2010, we started our fractionator at the Houston Central
plant, which adds approximately 22,000 barrels per day of
fractionation capacity to the gulf coast region and helps to
offset the effects of limited fractionation capacity on our
Texas segment. We will deliver purity propane and purity ethane
under new long-term contracts with Dow Hydrocarbons and
Resources via pipelines we own or lease, and we will sell the
remaining purity products via new truck racks installed at the
Houston Central plant.
34
Expanded commodity risk management
portfolio. We purchased puts for ethane (calendar
2011 and 2012), propane (calendar 2012), normal-butane (calendar
2012), crude oil (calendar 2011 and 2012) and iso-butane
(calendar 2012) at strike prices reflecting current market
conditions. We purchased these options from investment grade
counterparties in accordance with our risk management policy and
designated them as cash flow hedges to mitigate the impact of
decreases in NGL and crude oil prices. Our net costs for these
transactions were approximately $10.8 million.
Declaration of distribution. On April 14,
2010, our Board of Directors declared a cash distribution of
$0.575 per common unit for the first quarter of 2010. This
distribution will be paid on May 13, 2010 to all common
unitholders of record at the close of business on April 30,
2010.
Common unit offering. In March 2010, we issued
7,446,250 common units at an offering price of $23.10 per unit.
We used the net proceeds from the offering to repay a portion of
the outstanding indebtedness under our revolving credit
facility, and we expect to use the increased borrowing capacity
as needed for capital projects, acquisitions, hedging, working
capital and general corporate purposes.
Trends
and Uncertainties
This section, which describes recent changes in factors
affecting our business, should be read in conjunction with
How We Evaluate Our Operations and
How We Manage Our Operations below and
in Item 7 of our 2009
10-K. Many
of the factors affecting our business are beyond our control and
are difficult to predict.
Commodity
Prices and Producer Activity
Our gross margins and total distributable cash flow are
influenced by the prices of natural gas and NGLs, and by
drilling activity. Generally, prices affect the cash flow and
profitability of our Texas and Oklahoma segments directly. To
the extent that they influence the level of drilling activity,
commodity prices also affect all of our segments indirectly. For
a discussion of how we use hedging to reduce the effects of
commodity price fluctuations on our cash flow and profitability,
please read Item 3, Quantitative and Qualitative
Disclosures About Market Risk.
The long-term growth and sustainability of our business depends
on natural gas prices being at levels sufficient to provide
incentives, capital and adequate returns for producers to
maintain and increase natural gas exploration and production.
Commodity price fluctuations and the availability of capital are
among the factors that influence natural gas producers as they
schedule drilling projects. Low natural gas prices act as a
disincentive to producers, particularly when combined with high
operating costs or high third-party transportation costs.
Producers typically increase new drilling activity when natural
gas prices are sufficient to make drilling and production
economic and, depending on the severity and duration of an
unfavorable pricing environment, producers may suspend drilling
and completion activity to the degree they have become
uneconomic.
The level at which drilling and production become economic
depends on natural gas prices and a variety of other factors.
Other factors include the producers drilling, completion
and other operating costs, which are influenced by the
characteristics of the hydrocarbon reservoir, among other
things, and the extent to which the producer relies on commodity
price hedging. In addition, producers may drill when they
otherwise would not if drilling activity is necessary to
maintain their leasehold interests. For producers of rich gas
who share in the benefits of improved processing economics under
their sales contracts, the disincentive of low natural gas
prices could be offset as prices for NGLs increase. Improving
crude oil prices could also lead to increased production of
casinghead natural gas associated with oil production.
First-Quarter Commodity Prices. Crude oil
prices have continued the recovery that began in early 2009.
While natural gas and NGL prices remain stronger compared to
2009 lows, both have declined consistently since January 2010.
Because natural gas and NGL prices reached near-term highs in
January 2010, first-quarter averages for both are higher than
fourth-quarter 2009 averages despite declines in both for much
of the first quarter. Forward pricing on NYMEX reflects market
expectations that crude oil prices in the coming months will be
modestly higher compared to recent months and that natural gas
will stabilize in the range of the prices realized in recent
months. NGL forward-pricing curves indicate expectations that
NGL prices will also stabilize.
35
We believe that natural gas prices are influenced by regional
drilling activity, takeaway capacity, the severity of winter and
summer weather (and other factors that influence consumption and
demand), natural gas storage levels, liquefied natural gas
imports (and other competing supplies of natural gas), NGL
transportation and fractionation capacity and the overall
economy. While recent economic indicators increasingly support
the view that the recession has ended, the strength and
sustainability of an economic recovery remain uncertain. A
renewed slowdown in economic activity would likely result in
continued declines in natural gas and NGL prices and reduced
drilling activity.
Pricing Trends in Texas. After improving
significantly in late 2009, natural gas and NGL prices in Texas
began the year at
12-month
highs and declined through the first quarter of 2010 and the
second quarter of 2010 to date.
First-of-the-month
prices for natural gas on the Houston Ship Channel index were
$3.92 per MMBtu for April 2010 and $4.15 per MMBtu for May 2010,
and weighted-average daily prices for NGLs at Mt. Belvieu
through May 3, 2010, based on our first-quarter 2010
product mix, were $45.58 per barrel.
The following graph and table summarize prices for crude oil on
NYMEX and for natural gas and NGLs on the primary indices we use
for Texas pricing.
Texas
Prices for Crude Oil, Natural Gas and
NGLs(1)
|
|
|
(1)
|
|
Average crude oil prices are based
on NYMEX. Natural gas prices are
first-of-the-month
index prices. Average quarterly NGL prices are calculated based
on our weighted-average product mix at Mt. Belvieu for the
period indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly Data for Texas:
|
|
|
|
Q1 2009
|
|
|
Q2 2009
|
|
|
Q3 2009
|
|
|
Q4 2009
|
|
|
|
Q1 2010
|
|
Houston Ship Channel ($/MMBtu)
|
|
$
|
4.21
|
|
|
$
|
3.44
|
|
|
$
|
3.32
|
|
|
$
|
4.16
|
|
|
|
$
|
5.36
|
|
Mt. Belvieu ($/barrel)
|
|
$
|
25.81
|
|
|
$
|
30.12
|
|
|
$
|
35.09
|
|
|
$
|
42.96
|
|
|
|
$
|
47.66
|
|
NYMEX crude oil ($/barrel)
|
|
$
|
43.31
|
|
|
$
|
59.79
|
|
|
$
|
68.24
|
|
|
$
|
76.13
|
|
|
|
$
|
78.72
|
|
Service throughput (MMBtu/d)
|
|
|
644,752
|
|
|
|
630,674
|
|
|
|
613,234
|
|
|
|
576,224
|
|
|
|
|
582,958
|
|
Plant inlet (MMBtu/d)
|
|
|
558,115
|
|
|
|
559,597
|
|
|
|
543,994
|
|
|
|
497,368
|
|
|
|
|
457,233
|
|
NGLs produced (Bbls/d)
|
|
|
16,878
|
|
|
|
18,425
|
|
|
|
18,197
|
|
|
|
18,292
|
|
|
|
|
15,339
|
|
Segment gross margin (in thousands)
|
|
$
|
20,580
|
|
|
$
|
23,320
|
|
|
$
|
26,875
|
|
|
$
|
32,845
|
|
|
|
$
|
27,165
|
|
Pricing Trends in Oklahoma. After improving
significantly in late 2009, natural gas and NGL prices in
Oklahoma began 2010 at
18-month
highs and declined through the first quarter of 2010 and the
second quarter 2010 to date.
First-of-the-month
prices for natural gas on the CenterPoint East index were $3.70
per MMBtu for April
36
2010 and $3.97 per MMBtu for May 2010, and weighted-average
daily prices for NGLs at Conway through May 3, 2010, based
on our first quarter product mix, were $39.08 per barrel.
The following graph and table summarize prices for crude oil on
NYMEX and for natural gas and NGLs on the primary indices we use
for Oklahoma pricing.
Oklahoma
Prices for Crude Oil, Natural Gas and
NGLs(1)
|
|
|
(1)
|
|
Average crude oil prices are based
on NYMEX. Natural gas prices are
first-of-the-month
index prices. Average quarterly NGL prices are calculated based
on our weighted-average product mix at Conway for the period
indicated. Segment gross margin results exclude activities
attributable to our crude oil pipeline and related assets
discussed in Note 13, Discontinued Operations,
to our unaudited consolidated financial statements included in
Item 1 of this report.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly Data for Oklahoma:
|
|
|
|
Q1 2009
|
|
|
Q2 2009
|
|
|
Q3 2009
|
|
|
Q4 2009
|
|
|
|
Q1 2010
|
|
CenterPoint East ($/MMBtu)
|
|
$
|
3.37
|
|
|
$
|
2.70
|
|
|
$
|
2.98
|
|
|
$
|
4.01
|
|
|
|
$
|
5.22
|
|
Conway ($/barrel)
|
|
$
|
24.13
|
|
|
$
|
25.57
|
|
|
$
|
27.62
|
|
|
$
|
40.86
|
|
|
|
$
|
44.44
|
|
NYMEX crude oil ($/barrel)
|
|
$
|
43.31
|
|
|
$
|
59.79
|
|
|
$
|
68.24
|
|
|
$
|
76.13
|
|
|
|
$
|
78.72
|
|
Service throughput (MMBtu/d)
|
|
|
271,222
|
|
|
|
267,576
|
|
|
|
260,296
|
|
|
|
250,248
|
|
|
|
|
248,784
|
|
Plant inlet (MMBtu/d)
|
|
|
160,181
|
|
|
|
166,846
|
|
|
|
166,884
|
|
|
|
159,713
|
|
|
|
|
152,190
|
|
NGLs produced (Bbls/d)
|
|
|
15,309
|
|
|
|
15,981
|
|
|
|
16,474
|
|
|
|
16,123
|
|
|
|
|
15,334
|
|
Segment gross margin (in thousands)
|
|
$
|
14,300
|
|
|
$
|
17,472
|
|
|
$
|
18,284
|
|
|
$
|
26,628
|
|
|
|
$
|
24,275
|
|
Basis Trends. Prices for the first quarter of
2010 reflected a widening of the average basis differential
between Mt. Belvieu and Conway, which was $3.03 per barrel, as
compared to $2.09 per barrel for the fourth quarter of 2009.
Prices for purity ethane account for 52% of this basis
differential. At May 3, 2010, this basis differential was
$5.70 per barrel. The average basis differential between Houston
Ship Channel and CenterPoint East natural gas index prices was
$0.14 per MMBtu for the first quarter, slightly narrowed from
$0.15 per MMBtu for the fourth quarter of 2009, and was $0.18
per MMBtu for May 2010.
Pricing Trends in the Rocky Mountains. After
improving significantly in late 2009, Rocky Mountains natural
gas prices declined in the first quarter of 2010 and the second
quarter 2010 to date.
First-of-the-month
prices for natural gas on the Colorado Interstate Gas
(CIG) index were $3.57 per MMBtu for April and $3.67
per MMBtu for May 2010.
37
The following graph and table summarize prices for natural gas
on CIG, the primary index we use for the Rocky Mountains.
Rocky
Mountains Natural Gas
Prices(1)
|
|
|
(1)
|
|
Natural gas prices are
first-of-the-month index prices.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly Data for Rocky Mountains:
|
|
|
|
Q1 2009
|
|
|
Q2 2009
|
|
|
Q3 2009
|
|
|
Q4 2009
|
|
|
|
Q1 2010
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CIG ($/MMBtu)
|
|
$
|
3.27
|
|
|
$
|
2.36
|
|
|
$
|
2.67
|
|
|
$
|
3.96
|
|
|
|
$
|
5.14
|
|
Pipeline throughput
(MMBtu/d)(1)
|
|
|
1,005,998
|
|
|
|
980,694
|
|
|
|
952,126
|
|
|
|
965,033
|
|
|
|
|
931,319
|
|
Segment gross margin (in
thousands)(2)
|
|
$
|
799
|
|
|
$
|
711
|
|
|
$
|
634
|
|
|
$
|
1,110
|
|
|
|
$
|
1,103
|
|
|
|
|
(1)
|
|
Includes 100% of Bighorn and
Fort Union.
|
|
(2)
|
|
Excludes results and volumes
associated with our equity interests in Bighorn and
Fort Union.
|
First Quarter Drilling and Production
Activity. Drilling activity in lean gas areas
generally has remained low due to weaker natural gas prices and
has improved in rich gas areas, where crude oil and NGL
production have supported natural gas drilling economics.
Changes in drilling activity are reflected in our throughput
volumes only gradually because of the time required to drill,
complete and attach new wells or, when drilling is declining,
because of continuing production from already-completed wells.
Therefore, our volumes continue to show the negative effects of
last years sharp declines in drilling and do not fully
reflect the positive effects of recent improvements in rich gas
drilling activity.
Volume declines due to lower drilling activity in each of our
operating segments contributed to our overall lower volumes
compared to the first quarter of 2009. However, a decrease in
low-margin gas from a third-party pipeline in Texas and a
six-day
shutdown of our Houston Central plant in preparation for
start-up of
our fractionator were also significant factors.
In Texas, declines in our lean gas volumes are significantly
offset by increasing rich gas volumes, which is consistent with
our belief that, generally, rich gas drilling will show more
consistent improvement under the current market conditions. In
Oklahoma, however, we have seen increasing activity and volumes
in lean gas areas and relatively flat activity and volumes in
rich gas areas. Based on our conversations with producers in the
region, we
38
believe that a significant amount of this activity is supported
by commodity hedging or producers need to drill in order
to maintain their leasehold interests or to recover costs they
have already incurred.
While commodity prices and financial market conditions have
improved compared to this time last year, prices continue to
show some volatility, and drilling activity has been sporadic.
It remains uncertain when producers will undertake sustained
increases in drilling activity throughout the areas in which we
operate. If the pricing environment of the first quarter of 2010
continues, we anticipate sustained or increasing drilling
activity in areas that produce rich gas, for example the Eagle
Ford Shale trend in south Texas and the Barnett Shale Combo play
in north Texas, and a continued low level of drilling activity
in most areas that produce lean gas, for example the Powder
River Basin in Wyoming. We expect that many producers of lean
gas will wait to see sustained increases in natural gas prices
before resuming significant drilling activity, although other
factors such as commodity hedges or the need to maintain
leasehold interests will also influence their decisions. Forward
pricing suggests that NGL prices will improve modestly in the
near future and that natural gas prices will stabilize; however,
forward curves only reflect market expectations, and it is
uncertain to what extent they will influence producers
drilling decisions. In addition, as noted above, once drilling
activity increases, a recovery in volumes will be subject to
delays ranging from three months to as long as 18 months,
depending on the characteristics of the reservoir, for processes
involved in completing and attaching new wells.
Other Industry Trends. Due to higher NGL
prices and the completion of projects increasing NGL output, NGL
fractionation facilities are experiencing capacity constraints,
which we believe could lead to higher fractionation costs. If
NGL fractionation capacity remains constrained, these higher
costs could offset the benefits of improving NGL prices to some
extent. In April 2010, we started our fractionator at the
Houston Central plant, which we believe will allow us to benefit
from fractionation demand rather than operating subject to
capacity constraints that expose us to higher fractionation
costs.
Factors
Affecting Operating Results and Financial Condition
Our first-quarter 2010 results reflect the effects on our
volumes of limited drilling that followed 2009s weaker
pricing environment, and the interruption of operations at our
Houston Central plant to perform maintenance, complete the
connection for ethane and propane lines and to prepare for the
start-up of
our fractionator. Our results also are beginning to reflect the
offsetting effect of rich gas drilling that has followed
improvement in NGL prices. Relatively strong NGL prices in
Oklahoma and Texas combined with lower natural gas prices in
Texas during the first quarter of 2010 have continued to benefit
our processing margins. Our combined operating segment gross
margins increased 47% compared to the first quarter of 2009.
Consistent with our business strategy, we have used derivative
instruments to mitigate the effects of commodity price
fluctuations on our cash flow and profitability so that we can
continue to meet our debt service and capital expenditure
requirements, and our distribution objectives. For much of 2009,
cash settlements from our commodity hedge portfolio helped to
offset the decline in operating revenues attributable to lower
commodity prices. For the first quarter of 2010, improvements in
commodity prices have increased our operating segment cash flow
and reduced our cash flow from commodity hedge settlements. For
the first quarter of 2010, we received $7.0 million in net
cash settlements from our commodity hedge portfolio, compared to
$25.1 million for the first quarter of 2009.
How We
Evaluate Our Operations
We believe that investors benefit from having access to the
various financial and operating measures that our management
uses in evaluating our performance. These measures include the
following: (i) throughput volumes; (ii) segment gross
margin and total segment gross margin; (iii) operations and
maintenance expenses; (iv) general and administrative
expenses; (v) EBITDA and adjusted EBITDA and
(vi) total distributable cash flow. Segment gross margin,
total segment gross margin, EBITDA, adjusted EBITDA and total
distributable cash flow are non-GAAP financial measures. A
reconciliation of each non-GAAP measure to its most directly
comparable GAAP measure is provided below.
For additional discussion of each of these measures, see
How We Evaluate Our Operations under
Item 7 of our 2009
10-K.
39
Reconciliation of Non-GAAP Financial
Measures. The following table presents a
reconciliation of the non-GAAP financial measures of
(i) total segment gross margin (which consists of the sum
of individual segment gross margins and the results of our risk
management activities, which are included in corporate and
other) to the GAAP financial measure of operating income,
(ii) EBITDA and adjusted EBITDA to the GAAP financial
measures of net income (loss) and cash flows from operating
activities and (iii) total distributable cash flow to the
GAAP financial measure of net income (loss), for each of the
periods indicated.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Reconciliation of total segment gross margin to operating income:
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
13,912
|
|
|
$
|
15,971
|
|
Add: Operations and maintenance expenses
|
|
|
12,103
|
|
|
|
12,672
|
|
Depreciation and amortization
|
|
|
15,201
|
|
|
|
13,105
|
|
General and administrative expenses
|
|
|
10,542
|
|
|
|
10,725
|
|
Taxes other than income
|
|
|
1,162
|
|
|
|
786
|
|
Equity in earnings from unconsolidated affiliates
|
|
|
(1,795
|
)
|
|
|
(1,484
|
)
|
|
|
|
|
|
|
|
|
|
Total segment gross margin
|
|
$
|
51,125
|
|
|
$
|
51,775
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of EBITDA and adjusted EBITDA to net (loss)
income:
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,260
|
)
|
|
$
|
5,905
|
|
Add: Depreciation and
amortization(1)
|
|
|
15,201
|
|
|
|
13,165
|
|
Interest and other financing costs
|
|
|
14,945
|
|
|
|
14,448
|
|
Provision for income taxes
|
|
|
234
|
|
|
|
164
|
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
|
29,120
|
|
|
|
33,682
|
|
Add: Amortization of difference between the carried investment
and the underlying equity in net assets of equity investments
|
|
|
4,645
|
|
|
|
4,818
|
|
Copanos share of depreciation and amortization included in
equity in earnings from unconsolidated affiliates
|
|
|
1,537
|
|
|
|
1,557
|
|
Copanos share of interest and other financing costs
incurred by our equity method investments
|
|
|
371
|
|
|
|
508
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
35,673
|
|
|
$
|
40,565
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of EBITDA and adjusted EBITDA to cash flows from
operating activities:
|
|
|
|
|
|
|
|
|
Cash flow provided by operating activities
|
|
$
|
29,164
|
|
|
$
|
35,398
|
|
Add: Cash paid for interest and other financing costs
|
|
|
14,050
|
|
|
|
13,178
|
|
Equity in earnings from unconsolidated affiliates
|
|
|
1,795
|
|
|
|
1,484
|
|
Distributions from unconsolidated affiliates
|
|
|
(5,765
|
)
|
|
|
(5,371
|
)
|
Risk management activities
|
|
|
(597
|
)
|
|
|
(9,188
|
)
|
Changes in working capital and other
|
|
|
(9,527
|
)
|
|
|
(1,819
|
)
|
|
|
|
|
|
|
|
|
|
EBITDA
|
|
|
29,120
|
|
|
|
33,682
|
|
Add: Amortization of difference between the carried investment
and the underlying equity in net assets of equity investments
|
|
|
4,645
|
|
|
|
4,818
|
|
Copanos share of depreciation and amortization included in
equity in earnings from unconsolidated affiliates
|
|
|
1,537
|
|
|
|
1,557
|
|
Copanos share of interest and other financing costs
incurred by our equity method investments
|
|
|
371
|
|
|
|
508
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
35,673
|
|
|
$
|
40,565
|
|
|
|
|
|
|
|
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Reconciliation of net (loss) income to total distributable cash
flow:
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,260
|
)
|
|
$
|
5,905
|
|
Add: Depreciation and
amortization(1)
|
|
|
15,201
|
|
|
|
13,165
|
|
Amortization of commodity derivative options
|
|
|
7,978
|
|
|
|
9,188
|
|
Amortization of debt issue costs
|
|
|
895
|
|
|
|
1,270
|
|
Equity-based compensation
|
|
|
2,715
|
|
|
|
1,959
|
|
Distributions from unconsolidated affiliates
|
|
|
6,737
|
|
|
|
6,931
|
|
Unrealized loss associated with line fill contributions and gas
imbalances
|
|
|
1,582
|
|
|
|
166
|
|
Unrealized loss (gain) on derivatives
|
|
|
533
|
|
|
|
(239
|
)
|
Deferred taxes and other
|
|
|
(301
|
)
|
|
|
346
|
|
Less: Equity in earnings from unconsolidated affiliates
|
|
|
(1,795
|
)
|
|
|
(1,484
|
)
|
Maintenance capital expenditures
|
|
|
(1,431
|
)
|
|
|
(2,151
|
)
|
|
|
|
|
|
|
|
|
|
Total distributable cash
flow(2)
|
|
$
|
30,854
|
|
|
$
|
35,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes activity related to our crude oil pipeline and related
assets for the three months ended March 31, 2009, which are
classified as discontinued operations as discussed in
Note 13, Discontinued Operations, to our
unaudited consolidated financial statements included in
Item 1 of this report. |
|
(2) |
|
Prior to any retained cash reserves established by our Board of
Directors. |
How We
Manage Our Operations
Our management team uses a variety of tools to manage our
business. These tools include: (i) our economic models and
standardized processing margin (ii) flow and transaction
monitoring systems, (iii) producer activity evaluation and
reporting and (iv) an imbalance monitoring and control
system.
Our standardized processing margin is based on a
fixed set of assumptions, with respect to NGL composition and
fuel consumption per recovered gallon, which we believe is
generally reflective of our business. Because these assumptions
are held stable over time, changes in underlying natural gas and
NGL prices drive changes in the standardized processing margin.
Our results of operations may not necessarily correlate to the
changes in our standardized processing margin because of the
impact of factors other than commodity prices, such as volumes,
changes in NGL composition, recovery rates and variable contract
terms. However, we believe this calculation is representative of
the current operating commodity price environment of our Texas
processing operations, and we use this calculation to track
commodity price relationships. Our standardized processing
margins averaged $0.5745 and $0.181 per gallon during the three
months ended March 31, 2010 and 2009, respectively. The
average standardized processing margin for the period from
January 1, 1989 through March 31, 2010 is $0.1528 per
gallon.
For a further discussion, please read Item 7
How We Manage Our Operations under
Item 7 of our 2009
10-K.
Forward-Looking
Statements
This report contains certain forward-looking
statements within the meaning of the federal securities
laws. All statements, other than statements of historical fact
included in this report, including, but not limited to, those
under Our Results of Operations and
Liquidity and Capital Resources are
forward-looking statements. Statements included in this report
that are not historical facts, but that address activities,
events or developments that we expect or anticipate will or may
occur in the future, including things such as references to
future goals or intentions or other such references are
forward-looking statements. These statements can be identified
by the use of forward-looking terminology including
may, believe, expect,
anticipate, estimate,
continue, or similar words. These statements include
assertions related to plans for growth of our business, future
capital expenditures and competitive strengths and goals. We
make these statements based on our past experience and our
perception of
41
historical trends, current conditions and expected future
developments as well as other considerations we believe are
appropriate under the circumstances. Whether actual results and
developments in the future will conform to our expectations is
subject to numerous risks and uncertainties, many of which are
beyond our control. Therefore, actual outcomes and results could
materially differ from what is expressed, implied or forecasted
in these statements. Any differences could be caused by a number
of factors, including, but not limited to:
|
|
|
|
|
our ability to successfully integrate any acquired asset or
operations;
|
|
|
|
the volatility of prices and market demand for natural gas,
crude oil and NGLs;
|
|
|
|
our ability to continue to connect new sources of natural gas
supply;
|
|
|
|
our ability to access NGL fractionation capacity;
|
|
|
|
the ability of key producers to continue to drill and
successfully complete and attach new natural gas supplies;
|
|
|
|
our ability to retain key customers and contract with new
customers;
|
|
|
|
the availability of local, intrastate and interstate
transportation systems and other facilities for natural gas and
NGLs;
|
|
|
|
our ability to access our revolving credit facility and to
obtain additional financing on acceptable terms;
|
|
|
|
the effectiveness of our hedging program;
|
|
|
|
general economic conditions;
|
|
|
|
force majeure situations such as the loss of a market or
facility downtime;
|
|
|
|
the effects of government regulations and policies; and
|
|
|
|
other financial, operational and legal risks and uncertainties
detailed from time to time in our filings with the SEC.
|
Cautionary statements identifying important factors that could
cause actual results to differ materially from our expectations
are set forth in this report, including in conjunction with the
forward-looking statements referred to above. When considering
forward-looking statements, you should keep in mind the risk
factors and other cautionary statements set forth under
Item 1A, Risk Factors in Part II of this
report and in our 2009
10-K. All
forward-looking statements included in this report and all
subsequent written or oral forward-looking statements
attributable to us or persons acting on our behalf are expressly
qualified in their entirety by these cautionary statements. The
forward-looking statements speak only as of the date made, and
we undertake no obligation to publicly update or revise any
forward-looking statements, other than as required by law,
whether as a result of new information, future events or
otherwise.
42
Our
Results of Operations
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
($ in thousands)
|
|
|
Total segment gross
margin(1)(2)
|
|
$
|
51,125
|
|
|
$
|
51,775
|
|
Operations and maintenance
expenses(2)
|
|
|
12,103
|
|
|
|
12,672
|
|
Depreciation and
amortization(2)
|
|
|
15,201
|
|
|
|
13,105
|
|
General and administrative expenses
|
|
|
10,542
|
|
|
|
10,725
|
|
Taxes other than income
|
|
|
1,162
|
|
|
|
786
|
|
Equity in earnings from unconsolidated
affiliates(3)(4)(5)
|
|
|
(1,795
|
)
|
|
|
(1,484
|
)
|
|
|
|
|
|
|
|
|
|
Operating
income(2)
|
|
|
13,912
|
|
|
|
15,971
|
|
Gain on retirement of unsecured debt
|
|
|
|
|
|
|
3,939
|
|
Interest and other financing costs, net
|
|
|
(14,938
|
)
|
|
|
(14,402
|
)
|
Provision for income taxes
|
|
|
(234
|
)
|
|
|
(164
|
)
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
561
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,260
|
)
|
|
$
|
5,905
|
|
|
|
|
|
|
|
|
|
|
Total segment gross
margin:(8)
|
|
|
|
|
|
|
|
|
Oklahoma(2)
|
|
$
|
24,275
|
|
|
$
|
14,300
|
|
Texas
|
|
|
27,165
|
|
|
|
20,580
|
|
Rocky
Mountains(6)
|
|
|
1,103
|
|
|
|
799
|
|
|
|
|
|
|
|
|
|
|
Segment gross
margin(2)
|
|
|
52,543
|
|
|
|
35,679
|
|
Corporate and
other(7)
|
|
|
(1,418
|
)
|
|
|
16,096
|
|
|
|
|
|
|
|
|
|
|
Total segment gross
margin(1)(2)
|
|
$
|
51,125
|
|
|
$
|
51,775
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin per
unit:(8)
|
|
|
|
|
|
|
|
|
Oklahoma:
|
|
|
|
|
|
|
|
|
Service throughput
($/MMBtu)(2)
|
|
$
|
1.08
|
|
|
$
|
0.59
|
|
Texas:
|
|
|
|
|
|
|
|
|
Service throughput ($/MMBtu)
|
|
$
|
0.52
|
|
|
$
|
0.35
|
|
Volumes:(8)
|
|
|
|
|
|
|
|
|
Oklahoma:(9)
|
|
|
|
|
|
|
|
|
Service throughput (MMBtu/d)
|
|
|
248,784
|
|
|
|
271,222
|
|
Plant inlet volumes (MMBtu/d)
|
|
|
152,190
|
|
|
|
160,181
|
|
NGLs produced (Bbls/d)
|
|
|
15,334
|
|
|
|
15,309
|
|
Texas:(10)
|
|
|
|
|
|
|
|
|
Service throughput (MMBtu/d)
|
|
|
582,958
|
|
|
|
644,752
|
|
Pipeline throughput (MMBtu/d)
|
|
|
316,937
|
|
|
|
304,158
|
|
Plant inlet volumes (MMBtu/d)
|
|
|
457,233
|
|
|
|
558,195
|
|
NGLs produced (Bbls/d)
|
|
|
15,339
|
|
|
|
16,878
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures
|
|
$
|
1,431
|
|
|
$
|
2,151
|
|
Expansion capital expenditures
|
|
|
20,406
|
|
|
|
10,535
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
21,837
|
|
|
$
|
12,686
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance expenses:
|
|
|
|
|
|
|
|
|
Oklahoma(2)
|
|
$
|
5,433
|
|
|
$
|
5,616
|
|
Texas
|
|
|
6,569
|
|
|
|
7,054
|
|
Rocky Mountains
|
|
|
101
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
Total operations and maintenance
expenses(2)
|
|
$
|
12,103
|
|
|
$
|
12,672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Total segment gross margin is a
non-GAAP financial measure. See How We
Evaluate Our Operations for a reconciliation of total
segment gross margin to its most directly comparable GAAP
measure of operating income.
|
|
(2)
|
|
Excludes results attributable to
our crude oil pipeline and related assets for the three months
ended March 31, 2009, which are classified as discontinued
operations, as discussed in Note 13, Discontinued
Operations, in our unaudited consolidated financial
statements included in Item 1 of this report.
|
43
|
|
|
(3)
|
|
Includes results and volumes
associated with our interests in Bighorn and Fort Union.
Combined volumes gathered by Bighorn and Fort Union were
931,319 MMBtu/d and 1,005,998 MMBtu/d for the three
months ended March 31, 2010 and 2009, respectively.
|
|
|
|
(4)
|
|
Includes results and volumes
associated with our interest in Southern Dome. For the three
months ended March 31, 2010, plant inlet volumes for
Southern Dome averaged 14,130 MMBtu/d and NGLs produced
averaged 499 Bbls/d. For the three months ended
March 31, 2009, plant inlet volumes for Southern Dome
averaged 10,608 MMBtu/d and NGLs produced averaged
367 Bbls/d.
|
|
(5)
|
|
Includes results and volumes
associated with our interest in Webb Duval. Gross volumes
transported by Webb Duval, net of intercompany volumes, were
60,091 MMBtu/d and 88,740 MMBtu/d for the three months
ended March 31, 2010 and 2009, respectively.
|
|
(6)
|
|
Rocky Mountains segment gross
margin includes results from producer services, including
volumes purchased for resale, volumes gathered under firm
capacity gathering agreements with Fort Union, volumes
transported using our firm capacity agreements with WIC and
compressor rental services provided to Bighorn. Excludes results
and volumes associated with our interest in Bighorn and
Fort Union.
|
|
(7)
|
|
Corporate and other includes
results attributable to our commodity risk management activities.
|
|
(8)
|
|
Service throughput
means the volume of natural gas delivered to our wholly owned
processing plants by third-party pipelines plus our
pipeline throughput, which is the volume of natural
gas transported or gathered through our pipelines.
|
|
(9)
|
|
Plant inlet volumes and NGLs
produced represent total volumes processed and produced by the
Oklahoma segment at all plants, including plants owned by the
Oklahoma segment and plants owned by third parties. For the
three months ended March 31, 2010, plant inlet volumes
averaged 117,602 MMBtu/d and NGLs produced averaged
12,468 Bbls/d for plants owned by the Oklahoma segment. For
the three months ended March 31, 2009, plant inlet volumes
averaged 122,902 MMBtu/d and NGLs produced averaged
12,535 Bbls/d for plants owned by the Oklahoma segment.
Excludes volumes associated with our interest in Southern Dome.
|
|
(10)
|
|
Plant inlet volumes and NGLs
produced represent total volumes processed and produced by the
Texas segment at all plants, including plants owned by the Texas
segment and plants owned by third parties. Plant inlet volumes
averaged 450,417 MMBtu/d and NGLs produced averaged
14,852 Bbls/d for the three months ended March 31,
2010 for plants owned by the Texas segment. Plant inlet volumes
averaged 535,083 MMBtu/d and NGLs produced averaged
15,049 Bbls/d for the three months ended March 31,
2009 for plants owned by the Texas segment. Excludes volumes
associated with our interest in Webb Duval.
|
Three
Months Ended March 31, 2010 Compared To Three Months Ended
March 31, 2009
Net loss totaled $1.3 million, or $0.02 per unit on a
diluted basis for the three months ended March 31, 2010
compared to net income of $5.9 million, or $0.10 per unit
on a diluted basis for the three months ended March 31,
2009. The drivers of the $7.2 million change from the first
quarter of 2010 compared to the first quarter of 2009 primarily
included:
|
|
|
|
|
$3.9 million decrease in earnings related to the gain on
the retirement of debt in the three months ended March 31,
2009;
|
|
|
|
$2.1 million of additional depreciation and amortization
expenses primarily related to expanded operations in north Texas
and retirement of certain assets in Oklahoma;
|
|
|
|
$0.7 million decrease in total segment gross margin
consisting of a decrease of $17.5 million from our
commodity risk management activities, offset by a
$16.8 million increase in combined operating segment gross
margins primarily reflecting a
period-over-period
increase in average NGL prices of 84% on the Conway index and
85% on the Mt. Belvieu index, slightly offset by lower overall
service throughput volumes; and
|
|
|
|
$0.5 million increase in interest and other financing costs
primarily related to (i) an unrealized loss on interest
rate swaps for 2010 of $0.1 million compared to a
$0.1 million gain in 2009, a change of $0.2 million
and (ii) an increase of $0.3 million in interest paid
on interest rate swap arrangements.
|
Oklahoma Segment Gross Margin. Oklahoma
segment gross margin was $24.3 million for the three months
ended March 31, 2010 compared to $14.3 million for the
three months ended March 31, 2009, an increase of
$10.0 million, or 70%. The increase in segment gross margin
resulted primarily from
period-over-period
increases in average natural gas and NGL prices of 55% and 84%,
respectively. The Oklahoma segment gross margin per unit of
service throughput increased $0.49 per MMBtu to $1.08 per MMBtu
for the three months ended March 31, 2010 compared to $0.59
per MMBtu for the three months ended March 31, 2009. The
increase in segment gross margin was partially offset by
decreases in service throughput and plant inlet volumes of 8%
and 5%, respectively, however NGLs produced were flat. Please
read Trends and Uncertainties
Market and Industry Trends. The Oklahoma segment included
our crude oil pipeline activities through September 30,
2009. The segment gross margin results above exclude
$0.8 million related to our crude oil pipeline activities
for the three months ended
44
March 31, 2009. Please read Trends and
Uncertainties Market and Industry Trends
and Commodity Price and Producer Activity.
Texas Segment Gross Margin. Texas segment
gross margin was $27.2 million for the three months ended
March 31, 2010 compared to $20.6 million for the three
months ended March 31, 2009, an increase of
$6.6 million, or 32%. The Texas segment gross margin per
unit of service throughput increased $0.17 per MMBtu to $0.52
per MMBtu for the three months ended March 31, 2010
compared to $0.35 per MMBtu for the three months ended
March 31, 2009, primarily reflecting higher average NGL
prices, which increased 85%
period-over-period.
The increase in segment gross margin was offset by a 10% decline
in service throughput for the three months ended March 31,
2010 and higher average natural gas prices, which increased 27%
compared to the three months ended March 31, 2009. The
Texas segment gathered an average of 316,937 MMBtu/d of
natural gas, processed an average of 457,233 MMBtu/d of
natural gas at its plants and third-party plants and produced an
average of 15,339 Bbls/d of NGLs at its plants and
third-party plants during the first quarter of 2010,
representing an increase of 4% in volumes gathered and decreases
of 18% in volumes processed and 9% in NGLs produced as compared
to the first quarter of 2009. The decrease in NGL production was
primarily the result of decreased volumes delivered to our
Houston Central plant due in part to shutting down the plant for
six days to perform maintenance, complete the connection for
ethane and propane lines and prepare for the
start-up of
our fractionation facilities. For the three months ended
March 31, 2010, volumes originating from the Texas segment
and delivered to the Houston Central plant decreased 13% from
the three months ended March 31, 2009. Natural gas
delivered to the Houston Central plant and originating from
sources other than the Texas segment decreased 23% from the
first quarter of 2009 primarily as a result of a third party
pipeline temporarily diverting volumes away from the Houston
Central plant for ten days. Please read Trends
and Uncertainties Market and Industry Trends
and Commodity Price and Producer Activity.
Rocky Mountains Segment Gross Margin. Rocky
Mountains segment gross margin was $1.1 million for the
three months ended March 31, 2010 compared to
$0.8 million for the three months ended March 31,
2009, an increase of $0.3 million, or 38%. This increase is
primarily the result of a $0.4 million increase in
compressor rental income from Bighorn, which began during the
second quarter of 2009, offset by lower margin results from
producer services. These lower margin results were primarily due
to reduced production levels associated with a weak commodity
pricing environment in 2008 and 2009 creating disincentives for
producers to drill or to initiate de-watering programs on wells
previously drilled.
Corporate and Other. Corporate and other
includes our commodity risk management activities and was a loss
of $1.4 million for the three months ended March 31,
2010 compared to a gain of $16.1 million for the three
months ended March 31, 2009, a decrease of
$17.5 million. The loss for the three months ended
March 31, 2010 includes $8.0 million of non-cash
amortization expense relating to the option component of our
commodity derivative instruments and $0.4 million of
unrealized losses on our commodity derivative instruments offset
by $7.0 million of net cash settlements received on expired
commodity derivative instruments. The gain for the three months
ended March 31, 2009 includes $25.1 million of net
cash settlements received on expired commodity derivative
instruments and $0.2 million of unrealized
mark-to-market
gains on our commodity derivative instruments, offset by
$9.2 million of non-cash amortization expense relating to
the option component of our commodity derivative instruments.
Operations and Maintenance
Expenses. Operations and maintenance expenses
totaled $12.1 million for the three months ended
March 31, 2010 compared to $12.7 million for the three
months ended March 31, 2009. The 5% decrease is
attributable to decreases of $0.2 million in our Oklahoma
segment and $0.5 million in our Texas segment primarily due
to decreased costs for chemicals and field supplies and a
reduction in the rental costs of compressors; offset by an
increase of $0.1 million in our Rocky Mountains segment
related to overhaul expenditures on the compressors we lease to
Bighorn.
Depreciation and, Amortization. Depreciation
and amortization totaled $15.2 million for the three months
ended March 31, 2010 compared with $13.1 million for
the three months ended March 31, 2009, an increase of 16%.
This increase relates primarily to additional depreciation and
amortization recognized due to capital expenditures made
subsequent to March 31, 2009 including expenditures
relating to the completion of our Saint Jo plant and retirement
of certain assets in Oklahoma.
45
General and Administrative Expenses. General
and administrative expenses totaled $10.5 million for the
three months ended March 31, 2010 compared to
$10.7 million for the three months ended March 31,
2009. The 2% decrease consists primarily of a decrease of
(i) $0.8 million in expenses associated with
acquisition initiatives and (ii) a reduction of
$0.2 million in gains on the sale of certain assets, offset
by (i) a $0.6 million increase in personnel,
compensation and benefits costs and (ii) an increase in
legal and accounting fees of $0.2 million.
Interest and Other Financing Costs. Interest
and other financing costs totaled $14.9 million for the
three months ended March 31, 2010 compared to
$14.4 million for the three months ended March 31,
2009, an increase of $0.5 million, or 3%. Interest expense
related to our revolving credit facility totaled
$2.4 million (including net settlements paid under our
interest rate swaps of $1.5 million and net of
$0.5 million of capitalized interest) and $1.5 million
(including net settlements paid under our interest rate swaps of
$1.1 million and net of $1.2 million of capitalized
interest) for the three months ended March 31, 2010 and
2009, respectively. Interest and other financing costs for the
three months ended March 31, 2010 includes unrealized
mark-to-market
losses of $0.1 million on undesignated interest rate swaps
compared to unrealized
mark-to-market
gains of $0.1 million for the same period in 2009. Interest
expense on our senior unsecured notes decreased to
$11.6 million for the three months ended March 31,
2010 from $11.8 million for the three months ended
March 31, 2009, primarily related to interest savings as a
result of retiring $18.2 million of our 7.75% senior
unsecured notes due 2018 during the three months ended
March 31, 2009. Amortization of debt issue costs totaled
$0.9 million and $1.3 million for the three months
ended March 31, 2010 and 2009, respectively. Average
borrowings under our credit arrangements for the three months
ended March 31, 2010 and 2009 were $823.2 million and
$838.1 million with average interest rates of 7.4% for both
periods. Please read Liquidity and Capital
Resources Description of Our Indebtedness.
Gain on Unsecured Debt Retirement. During the
first quarter of 2009, we repurchased and retired
$18.2 million aggregate principal amount of our
7.75% senior unsecured notes due 2018 using available cash
and borrowings under our revolving credit facility. As a result
of repurchasing the notes below par value, we recognized a gain
of $3.9 million in the first quarter of 2009.
Cash
Flows
The following table summarizes our cash flows for each of the
periods indicated as reported in the historical consolidated
statements of cash flows found in Item 1 of this report.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Net cash provided by operating activities
|
|
$
|
29,164
|
|
|
$
|
35,398
|
|
Net cash used in investing activities
|
|
|
(18,441
|
)
|
|
|
(19,451
|
)
|
Net cash (used in) provided by financing activities
|
|
|
(1,267
|
)
|
|
|
4,662
|
|
Our cash flows are affected by a number of factors, some of
which we cannot control. These factors include industry and
economic conditions, as well as conditions in the financial
markets, prices and demand for our services, volatility in
commodity prices or interest rates, effectiveness of our hedging
program, operational risks and other factors.
Operating Cash Flows. Net cash provided by
operating activities was $29.2 million for the three months
ended March 31, 2010 compared to $35.4 million for the
three months ended March 31, 2009. The decrease in cash
provided by operating activities of $6.2 million was
attributable to the following changes:
|
|
|
|
|
risk management activities used an additional $8.6 million
of cash flow for the three months ended March 31, 2010 as
compared to the three months ended March 31, 2009,
primarily because we purchased commodity derivative instruments
at a total cost of $7.4 million during the three months
ended March 31, 2010, whereas in the three months ended
March 31, 2009, we did not purchase commodity derivative
instruments;
|
46
partially offset by:
|
|
|
|
|
a $1.9 million increase in operating activities (consisting
of a $2.1 million decrease in operating income and a
$4 million increase resulting from the timing of related
cash receipts and disbursements) for the three months ended
March 31, 2010 compared with the same period in 2009;
|
|
|
|
a $0.4 million increase in cash distributions received from
our unconsolidated affiliates (Bighorn, Fort Union, Webb
Duval and Southern Dome) in the three months ended
March 31, 2010 compared to the three months ended
March 31, 2009; and
|
|
|
|
a $0.1 million decrease in interest payments for the months
ended March 31, 2010 compared to the same period in 2009 as
a result of lower average borrowings.
|
Investing Cash Flows. Net cash used in
investing activities was $18.4 million and
$19.5 million for the three months ended March 31,
2010 and 2009, respectively. Investing activities for the three
months ended March 31, 2010 included
(i) $19.4 million of capital expenditures related to
the construction of the gathering lines upstream of our Saint Jo
plant,
rights-of-way
acquisition and construction of the Dewitt-Karnes pipeline
header in south Texas, as well as constructing well
interconnects to attach volumes in new areas, and
(ii) $0.4 million of investment in Bighorn offset by
(i) $1.0 million of distributions from Bighorn and
Southern Dome in excess of equity earnings and (ii) other
investing activities of $0.4 million. Investing activities
for the first quarter of 2009 included
(i) $19.8 million of capital expenditures related to
the construction of our Saint Jo plant and related projects,
progress payments for the purchase of compression and
constructing well interconnects to attach volumes in new areas,
(ii) $0.6 million of investment in Bighorn and
(iii) other investing activities of $0.6 million,
offset by $1.6 million of distributions from Bighorn,
Southern Dome and Webb Duval in excess of equity earnings.
Financing Cash Flows. Net cash used in
financing activities totaled $1.3 million during the three
months ended March 31, 2010 and included (i) net
repayments under our revolving credit facility of
$135.0 million and (ii) distributions to our
unitholders of $31.5 million, offset by (i) net
proceeds from our public offering of common units in March 2010
(including units issued upon the underwriters exercise of
their option to purchase additional units) of
$164.5 million and (ii) proceeds from the exercise of
unit options of $0.7 million. Net cash provided by
financing activities totaled $4.7 million during the three
months ended March 31, 2009 and included borrowings under
our revolving credit facility of $50.0 million, offset by
(i) $14.3 million to retire a portion of our
7.75% senior unsecured notes due 2018 and
(ii) distributions to our unitholders of $31.0 million.
Liquidity
and Capital Resources
Sources of Liquidity. Cash generated from
operations, borrowings under our revolving credit facility and
funds from equity and debt offerings are our primary sources of
liquidity. Our primary cash requirements consist of normal
operating expenses, capital expenditures to sustain existing
operations or generate additional revenues, interest payments on
our revolving credit facility and senior unsecured notes,
distributions to our unitholders and acquisitions of new assets
or businesses. Short-term cash requirements, such as operating
expenses, capital expenditures to sustain existing operations
and quarterly distributions to our unitholders, are expected to
be funded through operating cash flows. Long-term cash
requirements for expansion projects and acquisitions are
expected to be funded by several sources, including cash flows
from operating activities, borrowings under our revolving credit
facility and issuances of additional equity and debt securities,
as appropriate and subject to market conditions.
For additional discussion, please read Our
Long-Term Growth Strategy under Item 7 of our 2009
10-K.
Effects of Recent Economic Changes;
Outlook. Commodity prices during 2009 led to a
decline in drilling activity, and in turn a decline in the
volumes of natural gas we gathered and processed in 2009 and the
beginning of 2010. Although commodity prices and financial
market conditions have continued to recover, improvements in
drilling activity remain sporadic, and it remains unclear when
producers will undertake sustained increases in lean gas
drilling activity throughout the areas in which we operate. Our
ability to generate cash from operations, and to comply with the
covenants under our debt instruments, will be adversely affected
if we experience declining volumes in combination with
unfavorable commodity prices over a sustained period.
47
We have been able to offset the effects of lower prices using
commodity derivative instruments we acquired during the
favorable pricing environment that prevailed before late 2008;
however, we cannot use derivative instruments to offset the
effects of lower volumes. In addition, the strike prices of
derivative instruments we acquired in 2008 are substantially
higher than those of instruments we acquired in the fourth
quarter of 2009 and first and second quarters of 2010, as well
as the strike prices available for commodity derivative
instruments we could purchase today. Derivative instruments
reflect commodity price forward curves in effect at the time of
purchase, and our more recently purchased derivative instruments
will not be as beneficial as those we acquired in 2008.
We believe that cash from operations and our revolving credit
facility will provide sufficient liquidity to meet our
short-term capital requirements and to fund our committed
capital expenditures for at least the next 12 months. If
our plans or assumptions change, are inaccurate, or if we make
further acquisitions, we may need to raise additional capital.
Acquisitions and organic expansion have been, and our management
believes will continue to be, key elements of our business
strategy. In addition, we continue to consider opportunities for
strategic greenfield projects. The timing, size or success of
any acquisition or expansion effort and the associated potential
capital commitments are unpredictable. We may seek to fund all
or part of any such efforts with proceeds from debt or equity
issuances, or both. Our ability to obtain capital to implement
our growth strategy over the longer term will depend on our
future operating performance, financial condition and credit
rating and, more broadly, on the availability of equity and debt
financing, which will be affected by prevailing conditions in
our industry, the economy and the financial markets, and other
financial and business factors, many of which are beyond our
control.
Generally, we believe that financial markets now offer greater
liquidity than was available at the height of the financial
crisis, but at a higher cost than we would have experienced
before the financial crisis.
Capital Expenditures. The natural gas
gathering, transmission and processing businesses are
capital-intensive, requiring significant investment to maintain
and upgrade existing operations. Our capital requirements have
consisted primarily of, and we anticipate will continue to be:
|
|
|
|
|
maintenance capital expenditures, which are capital expenditures
employed to replace partially or fully depreciated assets to
maintain the existing operating capacity of our assets and to
extend their useful lives, or other capital expenditures that
are incurred in maintaining existing system volumes and related
cash flows; and
|
|
|
|
expansion capital expenditures, which are capital expenditures
made to expand or increase the efficiency of the existing
operating capacity of our assets. Expansion capital expenditures
include expenditures that facilitate an increase in volumes
within our operations, whether through construction or
acquisition. Expenditures that reduce our operating costs will
be considered expansion capital expenditures only if the
reduction in operating expenses exceeds cost reductions
typically resulting from routine maintenance.
|
During the three months ended March 31, 2010, our capital
expenditures totaled $21.8 million, consisting of
$1.4 million of maintenance capital and $20.4 million
of expansion capital. We funded our capital expenditures with
funds from operations and borrowings under our revolving credit
facility. Expansion capital expenditures were related to the
construction and gathering lines upstream of our Saint Jo plant,
rights-of-way
acquisition, construction of the Dewitt-Karnes pipeline header
in south Texas, completion of the Burbank plant in Oklahoma, as
well as constructing well interconnects to attach volumes in new
areas. Based on our current scope of operations, we anticipate
incurring approximately $10 million to $12 million of
maintenance capital expenditures over the next 12 months.
We anticipate incurring approximately $125 to $140 million
in expansion capital expenditures in 2010 primarily related to
enhancing the capabilities and capacities of our current asset
base.
Cash Distributions. The amount needed to pay
the current distribution of $0.575 per unit, or $2.30 per unit
annualized, to our common unitholders is as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
One Quarter
|
|
|
Four Quarters
|
|
|
Common
units(1)
|
|
$
|
38,134
|
|
|
$
|
152,536
|
|
|
|
|
|
|
|
|
|
|
48
|
|
|
(1)
|
|
Includes distributions on
restricted common units and phantom units issued under our
Long-Term Incentive Plan (LTIP). Distributions made
on restricted units and phantom units issued to date are subject
to the same vesting provisions as the restricted units and
phantom units. As of April 30, 2010, we had 105,101
outstanding restricted units and 738,056 outstanding phantom
units.
|
Our
Indebtedness
As of March 31, 2010 and December 31, 2009, our
aggregate outstanding indebtedness totaled $717.2 million
and $852.2 million, respectively, and we were in compliance
with our financial debt covenants under our revolving credit
facility and our incurrence covenant under the indentures of our
senior notes.
Credit Ratings. Moodys Investors Service
has assigned a Corporate Family rating of Ba3 with a negative
outlook, a B1 rating for our senior unsecured notes and a
Speculative Grade Liquidity rating of SGL-3.
Standard & Poors Ratings Services has assigned a
Corporate Credit Rating of BB- with a stable outlook and a B+
rating for our senior unsecured notes.
Revolving Credit Facility. As of
March 31, 2010, we had $135.0 million of outstanding
borrowings under our $550 million senior secured revolving
credit facility with Bank of America, N.A., as Administrative
Agent.
Our revolving credit facility matures on October 18, 2012.
Our revolving credit facility includes 29 lenders with
commitments ranging from $1 million to $60 million,
with the largest commitment representing 10.9% of the total
commitments. Future borrowings under the facility are available
for acquisitions, capital expenditures, working capital and
general corporate purposes, and the facility may be drawn on and
repaid without restriction so long as we are in compliance with
its terms, including the financial covenants described below.
Our revolving credit facility provides for up to
$50 million in standby letters of credit. As of
March 31, 2010 and December 31, 2009, we had no
letters of credit outstanding. We have not experienced any
difficulties in obtaining funding from any of our lenders, but
the lack of or delay in funding by one or more members of our
banking group could negatively affect our liquidity position.
At March 31, 2010, our ratio of total debt to EBITDA was
3.7x, and our ratio of EBITDA to interest expense was 3.5x.
Based on our ratio of total debt to EBITDA at March 31,
2010, we have approximately $247.0 million of available
borrowing capacity under the revolving credit facility before we
reach the maximum total debt to EBITDA ratio of 5.0 to 1.0.
If an event of default exists under the revolving credit
facility, our lenders could terminate their commitments to lend
to us and accelerate the maturity of our outstanding obligations
under the revolving credit facility.
Senior Unsecured Notes. The indentures
governing our senior unsecured notes restrict our ability to pay
cash distributions. Before we can pay a distribution to our
unitholders, we must demonstrate that our ratio of EBITDA to
fixed charges (as defined in the senior unsecured notes
indentures) is at least 1.75x. At March 31, 2010, our ratio
of EBITDA to fixed charges was 3.3x.
For additional details on the revolving credit facility and
Senior Notes, please read Note 5 Long-Term
Debt, to our unaudited consolidated financial statements
included in Item 1 of this report.
Off-Balance
Sheet Arrangements
We had no off-balance sheet arrangements as of March 31,
2010.
Recent
Accounting Pronouncements
For information on new accounting pronouncements, please read
Note 2 New Accounting Pronouncements, to our
unaudited consolidated financial statements included in
Item 1 of this report.
Critical
Accounting Policies
A discussion of our critical accounting policies for revenue
recognition, impairment of long-lived assets, risk management
activity and equity method of accounting for unconsolidated
affiliates, which remain unchanged, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operation Critical
Accounting Policies and Estimates in our Annual Report on
Form 10-K
for the year ended December 31, 2009.
49
|
|
Item 3.
|
Quantitative
and Qualitative Disclosures about Market Risk.
|
Market risk is the risk of loss arising from adverse changes in
market rates and prices. We are exposed to market risks,
including changes in commodity prices and interest rates. We may
use financial instruments such as options, swaps and other
derivatives to mitigate the effects of the identified risks. In
general, we attempt to hedge risks related to the variability of
our future cash flow and profitability resulting from changes in
applicable commodity prices or interest rates so that we can
maintain cash flows sufficient to meet debt service, required
capital expenditures, distribution objectives and similar
requirements. Our risk management policy prohibits the use of
derivative instruments for speculative purposes.
Commodity
Price Risk
NGL and natural gas prices are volatile and are impacted by
changes in fundamental supply and demand, as well as market
uncertainty, availability of NGL transportation and
fractionation capacity and a variety of additional factors that
are beyond our control. Our profitability is directly affected
by prevailing commodity prices primarily as a result of:
(i) processing or conditioning at our processing plants or
third-party processing plants, (ii) purchasing and selling
or gathering and transporting volumes of natural gas at
index-related prices and (iii) the cost of third-party
transportation and fractionation services. The following
discussion describes our commodity price risks as of
March 31, 2010. To the extent that they influence the level
of drilling activity, commodity prices also affect all of our
segments indirectly.
Oklahoma. A majority of the processing
contracts in our Oklahoma segment are
percentage-of-proceeds
arrangements. Under these arrangements, we purchase and process
natural gas from producers and sell the resulting residue gas
and NGL volumes. As payment, we retain an
agreed-upon
percentage of the sales proceeds, which results in effectively
long positions in both natural gas and NGLs. Accordingly, our
revenues and gross margins increase as natural gas and NGL
prices increase and revenues and gross margins decrease as
natural gas and NGL prices decrease. Our Oklahoma segment also
has fixed-fee contracts and
percentage-of-index
contracts.
Texas. Our Texas pipeline systems purchase
natural gas for transportation and resale and also transport and
provide other services on a
fee-for-service
basis. A significant portion of the margins we realize from
purchasing and reselling the natural gas is based on a
percentage of a stated index price. Accordingly, these margins
decrease in periods of low natural gas prices and increase
during periods of high natural gas prices. The fees we charge to
transport natural gas for the accounts of others are primarily
fixed, but our Texas contracts also include a
percentage-of-index
component in a number of cases.
While we have increasingly focused on obtaining fee-based
arrangements, a significant portion of the gas processed by our
Texas segment is still processed under keep-whole with fee
arrangements. Under these arrangements, increases in NGL prices
or decreases in natural gas prices generally have a positive
impact on our processing gross margins and, conversely, a
reduction in NGL prices or increases in natural gas prices
generally negatively impact our processing gross margins.
However, the ability of our Houston Central plant to operate in
a conditioning mode provides an operational hedge that allows us
to reduce our Texas processing operations commodity price
exposure. In conditioning mode, increases in natural gas prices
have a positive impact on our margins.
Rocky Mountains. Substantially all of our
Rocky Mountains contractual arrangements as well as the
contractual arrangements of Fort Union and Bighorn are
fixed-fee arrangements pursuant to which the gathering fee
income represents an agreed rate per unit of throughput. The
cash flow from these arrangements is directly related to natural
gas volumes and is not directly affected by commodity prices. To
the extent a sustained decline in commodity prices results in a
decline in volumes, our cash flow would also decline.
Other Commodity Price Risks. Although we seek
to maintain a position that is substantially balanced between
purchases and sales for future delivery obligations, we
experience imbalances between our natural gas purchases and
sales from time to time. For example, a producer could fail to
deliver or deliver in excess of contracted volumes, or a
customer could take more or less than contracted volumes. To the
extent our purchases and sales of natural gas are not balanced,
we face increased exposure to commodity prices with respect to
the imbalance.
50
We purchase and sell natural gas under a variety of pricing
arrangements, for example, by reference to first of the month
index prices, daily index prices or a weighted average of index
prices over a given period. Our goal is to minimize commodity
price risk by aligning the combination of pricing methods and
indices under which we purchase natural gas in each of our
segments with the combination under which we sell natural gas in
these segments, although it is not always possible to do so.
Basis risk is the risk that the value of a hedge may not move in
tandem with the value of the actual price exposure that is being
hedged. Any disparity in terms, such as product, time or
location, between the hedge and the underlying exposure creates
the potential for basis risk. Our long position in natural gas
in Oklahoma can serve as a hedge against our short position in
natural gas in Texas. To the extent we rely on natural gas from
our Oklahoma segment, which is priced primarily on the
CenterPoint East index, to offset a short position in natural
gas in our Texas segment, which is priced on the Houston Ship
Channel index, we are subject to basis risk. In addition, we are
subject to basis risk to the extent we hedge Oklahoma NGL
volumes because, due to the extremely limited forward market for
Conway-based hedge instruments, we use Mt. Belvieu-priced hedge
instruments for our Oklahoma NGL volumes. The CenterPoint East
and Houston Ship Channel indices and the Mt. Belvieu and Conway
indices historically have been highly correlated; however, these
indices displayed greater variability beginning in late 2008 and
for much of 2009. These basis differences returned to a
correlation more consistent with their historical pattern in
late 2009, but through May 3, 2010, the difference between
Mt. Belvieu and Conway had widened to $5.70 per barrel. To
mitigate basis risk affecting our natural gas positions in
Oklahoma and Texas, we entered into basis swaps on the
CenterPoint East index and the Houston Ship Channel indices for
2010.
Sensitivity. In order to calculate the
sensitivity of our total segment gross margin to commodity price
changes, we adjusted our operating models for actual commodity
prices, plant recovery rates and volumes. We have calculated
that a $0.01 per gallon change in either direction of NGL prices
would have resulted in a corresponding change of approximately
$0.2 million to our total segment gross margin for the
three months ended March 31, 2010. We also calculated that
a $0.10 per MMBtu increase in the price of natural gas would
have resulted in an immaterial change to our total segment gross
margin, and vice versa, for the three months ended
March 31, 2010. These relationships are not necessarily
linear. As actual prices have fallen below the strike prices of
our hedges in the first quarter of 2010, sensitivity to further
changes in commodity prices have been reduced. Also, if
processing margins are negative, we can operate our Houston
Central plant in a conditioning mode so that additional
increases in natural gas prices would have a positive impact on
our total segment gross margin.
Our Hedge
Portfolio
Commodity Hedges. As of March 31, 2010,
our commodity hedge portfolio totaled a net asset of
$42.9 million, which consists of assets aggregating
$47.5 million and liabilities aggregating
$4.6 million. For additional information, please read
Recent Developments in Item 2 of
this report and Note 11, Risk Management
Activities, to our unaudited consolidated financial
statements included in Item 1 of this report for tables
summarizing our commodity hedge portfolio as of March 31,
2010.
Interest Rate Swaps. As of March 31,
2010, the fair value of our interest rate swaps liability
totaled $8.1 million. For additional information on our
interest rate swaps, please read Note 11, Risk
Management Activities, to our unaudited consolidated
financial statements included in Item 1 of the report.
Counterparty
Risk
We are diligent in attempting to ensure that we provide credit
only to credit-worthy customers. However, our purchase and
resale of natural gas exposes us to significant credit risk, as
our margin on any sale is generally a very small percentage of
the total sale price. Therefore, a credit loss could be very
large relative to our overall profitability. For the three
months ended March 31, 2010, DCP Midstream (21%), ONEOK
Energy Services, L.P. (19%), ONEOK Hydrocarbons, L.P. (19%),
Kinder Morgan (8%) and Enterprise Products Operating, L.P. (7%),
collectively, accounted for approximately 74% of our revenue. As
of March 31, 2010, all of these companies, or their parent
companies, were rated investment grade by Moodys Investors
Service and Standard & Poors Ratings Services.
Companies accounting for another approximately 20% of our
revenue have an investment grade parent,
51
are themselves investment grade, have provided us with credit
support in the form of a letter of credit issued by an
investment grade financial institution or have provided
prepayment for our services.
We also diligently review the creditworthiness of other
counterparties to which we may have credit exposure, including
hedge counterparties. Our risk management policy requires that
we review and report the credit ratings of our hedging
counterparties on a monthly basis. As of March 31, 2010,
Barclays Bank PLC (47%), Deutsche Bank AG (29%) and JP Morgan
(11%) accounted for approximately 87% of the value of our net
commodity hedging positions. As of March 31, 2010, all of
these counterparties were rated A2 and A or better by
Moodys Investors Service and Standard &
Poors Ratings Services. Our hedge counterparties have not
posted collateral to secure their obligations to us.
We have historically experienced minimal collection issues with
our counterparties; however, nonpayment or nonperformance by one
or more significant counterparties could adversely impact our
liquidity.
|
|
Item 4.
|
Controls
and Procedures.
|
As required by
Rule 13a-15(b)
of the Exchange Act, we have evaluated, under the direction of
our Chief Executive Officer and Chief Financial Officer, the
effectiveness of the design and operation of our disclosure
controls and procedures (as defined in
Rules 13a-15(e)
and
15d-15(e)
under the Exchange Act) as of the end of the period covered by
this report. Our disclosure controls and procedures are designed
to provide reasonable assurance that the information required to
be disclosed by us in reports that we file under the Exchange
Act is accumulated and communicated to our management, including
our Chief Executive Officer and Chief Financial Officer, as
appropriate, to allow timely decisions regarding required
disclosure and is recorded, processed, summarized and reported
within the time periods specified in the rules and forms of the
SEC. Based upon the evaluation, our Chief Executive Officer and
Chief Financial Officer have concluded that our disclosure
controls and procedures were effective at March 31, 2010 at
the reasonable assurance level. There has been no change in our
internal controls over financial reporting (as defined in
Rule 13a-15(f)
under the Exchange Act) that occurred during the quarter ended
March 31, 2010 that has materially affected or is
reasonably likely to materially affect such internal controls
over financial reporting.
52
PART II-OTHER
INFORMATION
|
|
Item 1.
|
Legal
Proceedings.
|
Please read Note 9, Commitments and
Contingencies, to our unaudited consolidated financial
statements included in Part I, Item 1 of this report
which is incorporated in this item by reference.
In addition to the factors discussed elsewhere in this report,
including the financial statements and related notes, you should
consider carefully the risks and uncertainties described in this
item and under Item 1A, Risk Factors, in our
Annual Report on
Form 10-K
for the year ended December 31, 2009. These risks and
uncertainties could materially adversely affect our business,
financial condition and results of operations. If any of these
risks or uncertainties were to occur, our business, financial
condition or results of operation could be materially adversely
affected.
Federal
and state legislative and regulatory initiatives relating to
hydraulic fracturing could result in increased costs and
additional operating restrictions or delays as well as adversely
affect our services.
The federal Congress is considering legislation that would amend
the federal Safe Drinking Water Act by repealing an exemption
for the underground injection of hydraulic fracturing fluids
near drinking water sources. Hydraulic fracturing is an
important and commonly used process for the completion of
natural gas, and to a lesser extent, oil wells in shale
formations, and involves the pressurized injection of water,
sand and chemicals into rock formations to stimulate natural gas
production. Sponsors of the legislation have asserted that
chemicals used in the fracturing process could adversely affect
drinking water supplies. If enacted, the legislation could
result in additional regulatory burdens for producers such as
permitting, construction, financial assurance, monitoring,
recordkeeping, and plugging and abandonment requirements. The
legislation also proposes requiring the disclosure of chemical
constituents used in the fracturing process to state or federal
regulatory authorities, who would then make such information
publicly available. The availability of this information could
make it easier for third parties opposing the hydraulic
fracturing process to initiate legal proceedings based on
allegations that specific chemicals used in the fracturing
process could adversely affect groundwater. In addition, various
state and local governments are considering increased regulatory
oversight of hydraulic fracturing through additional permit
requirements, operational restrictions, and temporary or
permanent bans on hydraulic fracturing in certain
environmentally sensitive areas such as watersheds. The adoption
of any federal or state legislation or implementing regulations
imposing reporting obligations on, or otherwise limiting, the
hydraulic fracturing process could make it more difficult and
costly for producers to complete natural gas wells in shale
formations and adversely affect the gathering, processing and
fractionation services that we render for those producers.
Moreover, the U.S. Environmental Protection Agency, or
EPA, announced only recently, on March 18,
2010, that it has allocated $1.9 million in 2010 and has
requested funding in fiscal year 2011 for conducting a
comprehensive research study on the potential adverse impacts
that hydraulic fracturing may have on water quality and public
health. Consequently, even if the current federal legislation is
not adopted, the performance of the hydraulic fracturing study
by the EPA could spur further action at a later date towards
federal legislation and regulation of hydraulic fracturing
activities.
53
Exhibits not incorporated by reference to a prior filing are
designated by an asterisk (*) and are filed herewith; all
exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.
|
|
|
|
|
Number
|
|
Description
|
|
|
2
|
.1
|
|
Purchase Agreement dated as of August 31, 2007 among Copano
Energy, L.L.C., Copano Energy/Rocky Mountains, L.L.C., and
Cantera Resources Holdings LLC (incorporated by reference to
Exhibit 2.1 to Current Report on
Form 8-K
filed October 25, 2007).
|
|
2
|
.2
|
|
Contribution Agreement dated as of April 5, 2007 by and
among Cimmarron Gathering GP, LLC, Taos Gathering, LP and
Cimmarron Transportation, L.L.C. and Copano Energy, L.L.C.
(incorporated by reference to Exhibit 2.1 to Current Report
on
Form 8-K
filed April 11, 2007).
|
|
3
|
.1
|
|
Certificate of Formation of Copano Energy Holdings, L.L.C. (now
Copano Energy, L.L.C.) (incorporated by reference to
Exhibit 3.1 to Registration Statement on
Form S-1
filed July 30, 2004).
|
|
3
|
.2
|
|
Certificate of Amendment to Certificate of Formation of Copano
Energy Holdings, L.L.C. (now Copano Energy, L.L.C.)
(incorporated by reference to Exhibit 3.2 to Registration
Statement on
Form S-1
filed July 30, 2004).
|
|
3
|
.3
|
|
Third Amended and Restated Limited Liability Company Agreement
of Copano Energy, L.L.C. (incorporated by reference to
Exhibit 3.1 to Current Report on
Form 8-K
filed April 30, 2007).
|
|
3
|
.4
|
|
Amendment No. 1 to Third Amended and Restated Limited
Liability Company Agreement of Copano Energy, L.L.C.
(incorporated by reference to Exhibit 3.1 to Current Report
on
Form 8-K
filed May 4, 2007).
|
|
3
|
.5
|
|
Amendment No. 2 to Third Amended and Restated Limited
Liability Company Agreement of Copano Energy, L.L.C. dated
October 19, 2007 (incorporated by reference to
Exhibit 3.1 to Current Report on
Form 8-K
filed October 25, 2007).
|
|
3
|
.6
|
|
Amendment No. 3 to Third Amended and Restated Limited
Liability Company Agreement of Copano Energy, L.L.C., dated
October 19, 2007 (incorporated by reference to
Exhibit 3.2 to Current Report on
Form 8-K
filed October 25, 2007).
|
|
4
|
.1
|
|
Indenture dated as of February 7, 2006, among Copano
Energy, L.L.C., Copano Energy Finance Corporation, the
Guarantors parties thereto and U.S. Bank National Association,
as trustee (incorporated by reference to Exhibit 4.1 to
Current Report on
Form 8-K
filed February 8, 2006).
|
|
4
|
.2
|
|
Rule 144A Global Note representing $224,500,000 principal
amount of 8.125% Senior Notes due 2016 (incorporated by
reference to Exhibit 4.2 to Current Report on
Form 8-K
filed February 8, 2006).
|
|
4
|
.3
|
|
Regulation S Global Note representing $500,000 principal
amount of 8.125% Senior Notes due 2016 (incorporated by
reference to Exhibit 4.3 to Current Report on
Form 8-K
filed February 8, 2006).
|
|
4
|
.4
|
|
Indenture, dated May 16, 2008, among Copano Energy, L.L.C.,
Copano Energy Finance Corporation, the Subsidiary Guarantors
named therein and U.S. Bank National Association, as trustee
(incorporated by reference to Exhibit 4.1 to Current Report
on
Form 8-K
filed May 19, 2008).
|
|
4
|
.5
|
|
Form of Global Note representing 7.75% Senior Notes due
2018 (included in 144A/Regulation S Appendix to
Exhibit 4.7 above).
|
|
10
|
.1
|
|
Administrative and Operating Services Agreement effective
January 1, 2010, among Copano/Operations, Inc. and CPNO
Services, L.P. (incorporated by reference to Exhibit 10.3
to Annual Report on
Form 10-K
filed March 1, 2010).
|
|
10
|
.2
|
|
2010 Administrative Guidelines for the Copano Energy, L.L.C.
Management Incentive Compensation Plan (incorporated by
reference to Exhibit 10.1 to Current Report on
Form 8-K
filed February 23, 2010).
|
|
31
|
.1*
|
|
Sarbanes-Oxley Section 302 certification of Principal
Executive Officer.
|
|
31
|
.2*
|
|
Sarbanes-Oxley Section 302 certification of Principal
Financial Officer.
|
|
32
|
.1*
|
|
Sarbanes-Oxley Section 906 certification of Principal
Executive Officer.
|
|
32
|
.2*
|
|
Sarbanes-Oxley Section 906 certification of Principal
Financial Officer.
|
|
|
|
* |
|
Filed herewith. |
|
|
|
Portions of this exhibit have been omitted pursuant to a request
for confidential treatment. |
54
SIGNATURES
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, in the
City of Houston, State of Texas, on May 7, 2010.
Copano Energy, L.L.C.
|
|
|
|
By:
|
/s/ R.
Bruce Northcutt
|
R. Bruce
Northcutt
President and Chief Executive Officer
(Principal Executive Officer)
Carl A. Luna
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
55