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Copano Energy Reports Second Quarter 2010 Results
05 Aug, 2010 @ 04:15 pm EDT
HOUSTON, Aug. 5 /PRNewswire-FirstCall/ -- Copano Energy, L.L.C. (Nasdaq: CPNO) today announced its financial results for the three and six months ended June 30, 2010.
"We are pleased with the sequential improvement in our second quarter distributable cash flow," said Bruce Northcutt, Copano Energy's President and Chief Executive Officer. "Despite declining NGL prices during the quarter, second quarter distribution coverage was higher than first quarter coverage primarily due to the successful start up of the fractionation facility at our Houston Central plant and continued volume growth behind our Saint Jo plant."
"As we move into the second half of the year, we believe producer activity behind our pipelines in the Eagle Ford Shale, Barnett Shale Combo Play and Woodford Shale will drive growth in our distributable cash flow and distribution coverage," Northcutt added.
Second Quarter Financial Results
Revenue for the second quarter of 2010 increased 28% to $230.1 million compared to $180.2 million for the second quarter of 2009. Total segment gross margin increased to $56.8 million for the second quarter of 2010 compared to $51.1 million for the first quarter of 2010 and to $52.3 million for the second quarter of 2009, increases of 11% and 9%, respectively.
Adjusted EBITDA for the second quarter of 2010 increased to $39.7 million compared to $35.7 million for the first quarter of 2010 and to $39.0 million for the second quarter of 2009. Non-cash amortization expense relating to the option component of Copano's risk management portfolio, which is not added back in determining adjusted EBITDA, totaled $8.1 million, $8.0 million and $9.3 million, respectively, for the second quarter of 2010, the first quarter of 2010 and the second quarter of 2009.
Total distributable cash flow for the second quarter of 2010 increased to $33.5 million from $30.9 million in the first quarter, an increase of 8%, and from $32.9 million for the second quarter of 2009, an increase of 2%. Second quarter 2010 total distributable cash flow represents 87% coverage of the second quarter distribution of $0.575 per unit, based on total common units outstanding on the distribution record date.
Net loss for the second quarter of 2010 totaled $21.1 million, or $0.32 per unit on a diluted basis, and includes a non-cash impairment charge of $25.0 million related to Copano's investment in its unconsolidated affiliate, Bighorn Gas Gathering, L.L.C. (Bighorn). Net income was $6.0 million, or $0.10 per unit on a diluted basis, for the second quarter of 2009. Drivers of the $27.1 million decrease primarily included:
-- a $25.8 million decrease in equity in earnings of unconsolidated
affiliates as a result of the non-cash impairment charge mentioned
above. The non-cash impairment charge primarily resulted from a
continued weak Rocky Mountains pricing environment for natural gas, lack
of drilling activity in Wyoming's Powder River Basin and a downward
shift in the Colorado Interstate Gas forward price curve;
-- a $2.2 million decrease in earnings related to additional depreciation
and amortization expenses primarily related to expanded operations in
Texas;
-- a $2.4 million increase in general and administrative expenses ($1.6
million), property and other taxes ($0.5 million) and operations and
maintenance expenses ($0.3 million);
-- a $1.3 million increase in interest and other financing costs primarily
related to (i) an unrealized gain on interest rate swaps for 2010 of
$0.9 million compared to a $2.1 million gain in 2009 and (ii) an
increase of $0.1 million in interest expense related to Copano's senior
credit facility;
offset by:
-- a $4.6 million increase in total segment gross margin consisting of a
$13.2 million increase in combined operating segment gross margins
primarily reflecting average NGL price increases of 42% on the Conway
index and 43% on the Mt. Belvieu index, offset in part by lower overall
service throughput volumes and a decrease of $8.6 million from Copano's
commodity risk management activities.
Weighted average diluted units outstanding totaled 65.5 million for the second quarter of 2010 as compared to 57.9 million for the same period in 2009.
Segment gross margin, total segment gross margin, EBITDA, adjusted EBITDA and total distributable cash flow are non-GAAP financial measures that are reconciled to the most directly comparable GAAP measures at the end of this news release.
Second Quarter Operating Results by Segment
Copano manages its business in three geographical operating segments: Oklahoma, which provides midstream natural gas services in central and east Oklahoma; Texas, which provides midstream natural gas services in Texas and also includes a processing plant in southwest Louisiana; and the Rocky Mountains, which provides services to producers in Wyoming's Powder River Basin and includes managing member interests in Bighorn of 51% and in Fort Union Gas Gathering, L.L.C. (Fort Union) of 37.04%.
Oklahoma
Segment gross margin for Oklahoma increased 25% for the second quarter of 2010 to $21.8 million, compared to $17.5 million for the second quarter of 2009. The increase resulted primarily from a 28% increase in realized margins on service throughput compared to the second quarter of 2009 ($0.92 per MMBtu in 2010 compared to $0.72 per MMBtu in 2009), reflecting higher NGL and natural gas prices. During the second quarter of 2010, weighted-average NGL prices on the Conway index, based on Copano's product mix for the period, were $36.34 per barrel compared to $25.57 per barrel during the second quarter of 2009, an increase of 42%. During the second quarter of 2010, natural gas prices on the CenterPoint East index averaged $3.86 per MMBtu compared to $2.70 per MMBtu during the second quarter of 2009, an increase of 43%.
The Oklahoma segment gathered an average of 259,972 MMBtu/d of natural gas, processed an average of 156,204 MMBtu/d of natural gas and produced an average of 16,653 Bbls/d of NGLs at its own plants and third-party plants during the second quarter of 2010. In comparison to the second quarter of 2009, this represents a 3% decrease in service throughput, a 6% decrease in plant inlet volumes and a 4% increase in NGLs produced. The decrease in service throughput is primarily attributable to reduced drilling in rich gas areas, normal production declines and weather related issues during 2010.
Texas
Segment gross margin for Texas increased 36% for the second quarter of 2010 to $31.8 million, compared to $23.3 million for the second quarter of 2009. The increase resulted primarily from a 51% increase in realized margins on service throughput compared to the second quarter of 2009 ($0.62 per MMBtu in 2010 compared to $0.41 per MMBtu in 2009), reflecting higher NGL prices and the impact of the start up of Copano's fractionation facilities. During the second quarter of 2010, weighted-average NGL prices on the Mt. Belvieu index, based on Copano's product mix for the period, were $43.14 per barrel compared to $30.12 per barrel during the second quarter of 2009, an increase of 43%. During the second quarter of 2010, natural gas prices on Houston Ship Channel index averaged $4.04 per MMBtu compared to $3.44 per MMBtu during the second quarter of 2009, an increase of 17%.
The increase in realized margins for the Texas segment was offset by decreased service throughput and processing volumes. During the second quarter of 2010, the Texas segment provided gathering, transportation and processing services for an average of 559,876 MMBtu/d of natural gas compared to 630,674 MMBtu/d for the second quarter of 2009, a decrease of 11%. The Texas segment gathered an average of 327,839 MMBtu/d of natural gas, processed an average of 469,019 MMBtu/d of natural gas at its plants and third-party plants and produced an average of 18,382 Bbls/d of NGLs at its plants and third-party plants during the second quarter of 2010, representing an increase of 13% of volumes gathered, a decrease of 16% of volumes processed and flat NGL production as compared to the second quarter of 2009. Volumes originating from the Texas segment and delivered to the Houston Central plant decreased 6% from the second quarter of 2009. Lower margin volumes delivered to the Houston Central plant and originating from sources other than the Texas segment decreased 29% from the second quarter of 2009 primarily as a result of a third party pipeline diverting volumes away from the Houston Central plant during the quarter.
Rocky Mountains
Segment gross margin for Rocky Mountains totaled $1.1 million in the second quarter of 2010 compared to $0.7 million for the second quarter of 2009. The increase in segment gross margin was the result of higher compressor rental income from Bighorn, which began during the second quarter of 2009.
The Rocky Mountains segment results do not include the financial results and volumes associated with Copano's interests in Bighorn and Fort Union, which are accounted for under the equity method of accounting and are shown in Copano's financial statements under "Equity in earnings from unconsolidated affiliates." Average pipeline throughput for Bighorn and Fort Union on a combined basis decreased 8% to 900,047 MMBtu/d in the second quarter of 2010 as compared to 980,694 MMBtu/d in the second quarter of 2009 as the weak Rocky Mountains pricing environment has continued to delay drilling activity.
Corporate and Other
Corporate and other gross margin includes Copano's commodity risk management activities. These activities contributed a gain of $2.1 million for the second quarter of 2010 compared to $10.8 million for the second quarter of 2009. The gain for the second quarter of 2010 included $8.1 million of non-cash amortization expense relating to the option component of Copano's risk management portfolio offset by $9.5 million of net cash settlements received for expired commodity derivative instruments and $0.7 million of unrealized gains on undesignated economic hedges. The second quarter 2009 gain included $20.8 million of net cash settlements received for expired commodity derivative instruments offset by $0.7 million of unrealized mark-to-market losses on undesignated economic hedges and $9.3 million of non-cash amortization expense relating to the option component of Copano's risk management portfolio.
Year to Date Financial Results
Revenue for the six months ended June 30, 2010 increased 30% to $496.7 million compared to $381.3 million for the same period last year. Total segment gross margin was $108.0 million for the first six months of 2010 compared to $104.0 million for the same period in 2009.
Adjusted EBITDA for the six months ended June 30, 2010 decreased 5% to $75.3 million compared to $79.5 million for the same period last year. Non-cash amortization expense relating to the option component of Copano's risk management portfolio, which is not added back in determining adjusted EBITDA, totaled $16.0 million and $18.5 million, respectively, for the six months ended June 30, 2010 and 2009.
Total distributable cash flow for the first six months of 2010 decreased to $64.3 million from $68.0 million for the same period in 2009, primarily because 2009 results included a $3.9 million gain on the retirement of debt in 2009.
Net loss for the six months ended June 30, 2010 totaled $22.4 million, or $0.36 per unit on a diluted basis, and includes a non-cash impairment charge of $25.0 million related to Copano's investment in Bighorn. Net income was $11.9 million, or $0.21 per unit on a diluted basis, for the six months ended June 30, 2009. Drivers of the $34.3 million decrease primarily included:
-- a $25.4 million decrease in equity in earnings of unconsolidated
affiliates as a result of the non-cash impairment charge mentioned
above;
-- a $3.9 million decrease in earnings related to the gain on the
retirement of debt in 2009;
-- $4.3 million of additional depreciation and amortization expenses
primarily related to expanded operations in Texas;
-- a $2.0 million increase in general and administrative expenses and
property and other taxes;
-- a $0.8 million decrease in discontinued operations and taxes;
-- a $1.8 million increase in interest and other financing costs primarily
related to (i) an unrealized gain on interest rate swaps for 2010 of
$0.8 million compared to a $2.2 million gain in 2009 and (ii) a decrease
of capitalized interest of $1.0 million, offset in part by a decrease in
interest expense ($0.2 million) and amortization of debt issuance costs
($0.4 million) related to Copano's senior unsecured notes;
offset by:
-- a $3.9 million increase in total segment gross margin consisting of a
$30.1 million increase in combined operating segment gross margins
primarily reflecting average NGL price increases of 62% on the Conway
index and 61% on the Mt. Belvieu index, offset in part by lower overall
service throughput volumes and a decrease of $26.2 million from Copano's
commodity risk management activities.
Weighted average diluted units outstanding totaled 61.9 million for the six months ended June 30, 2010 as compared to 57.9 million for the same period in 2009.
Cash Distributions
On July 14, 2010, Copano announced its second quarter 2010 cash distribution of $0.575 per unit, or $2.30 per unit on an annualized basis, for all of its outstanding common units. This distribution is unchanged from the first quarter of 2010 and will be paid on August 12, 2010 to common unitholders of record at the close of business on August 2, 2010.
Conference Call Information
Copano will hold a conference call to discuss its second quarter 2010 financial results and recent developments on August 6, 2010 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time). To participate in the call, dial (480) 629-9821 and ask for the Copano call 10 minutes prior to the start time, or access it live over the internet at www.copanoenergy.com on the "Investor Overview" page of the "Investor Relations" section of Copano's website.
A replay of the audio webcast will be available shortly after the call on Copano's website. A telephonic replay will be available through August 13, 2010 by calling (303) 590-3030 and using the pass code 4334792#.
Use of Non-GAAP Financial Measures
This news release and the accompanying schedules include the non-generally accepted accounting principles, or non-GAAP, financial measures of segment gross margin, total segment gross margin, EBITDA, adjusted EBITDA and total distributable cash flow. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States, or GAAP. Non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income (loss), operating income (loss), income (loss) from continuing operations, cash flows from operating activities or any other GAAP measure of liquidity or financial performance. Copano uses non-GAAP financial measures as measures of its core profitability, liquidity position or to assess the financial performance of its assets. Copano believes that investors benefit from having access to the same financial measures that its management uses in evaluating Copano's core profitability, liquidity position or financial performance.
Houston-based Copano Energy, L.L.C. is a midstream natural gas company with operations in Oklahoma, Texas, Wyoming and Louisiana. Its assets include approximately 6,400 miles of active natural gas gathering and transmission pipelines, 250 miles of NGL pipelines and eight natural gas processing plants, with more than one billion cubic feet per day of combined processing capacity and 22,000 barrels per day of fractionation capacity. For more information, please visit www.copanoenergy.com.
This press release includes "forward-looking statements," as defined by the Securities and Exchange Commission. Statements that address activities, or events that Copano believes will or may occur in the future are forward-looking statements. These statements include, but are not limited to, statements about future producer activity and Copano's total distributable cash flow and distribution coverage. These statements are based on management's experience and perception of historical trends, current conditions, expected future developments and other factors management believes are reasonable. Important factors that could cause actual results to differ materially from those in the forward-looking statements include the following risks and uncertainties, many of which are beyond Copano's control: The volatility of prices and market demand for natural gas and natural gas liquids; Copano's ability to continue to obtain new sources of natural gas supply and retain its key customers; the impact on volumes and resulting cash flow of technological, economic and other uncertainties inherent in estimating future production and producers' ability to drill and successfully complete and attach new natural gas supplies and the availability of downstream transportation systems and other facilities for natural gas and NGLs; higher construction costs or project delays due to inflation, limited availability of required resources, or the effects of environmental, legal or other uncertainties; general economic conditions; the effects of government regulations and policies; and other financial, operational and legal risks and uncertainties detailed from time to time in Copano's filings with the Securities and Exchange Commission.
Contacts: Carl Luna, SVP & CFO
Copano Energy, L.L.C.
713-621-9547
Jack Lascar /jlascar@drg-
e.com
Anne Pearson /
apearson@drg-e.com
DRG&E / 713-529-6600
- financial statements to follow -
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months Six Months
Ended June 30, Ended June 30,
-------------- --------------
2010 2009 2010 2009
(In thousands, except per
unit information)
Revenue:
Natural gas
sales $84,819 $64,517 $205,035 $159,496
Natural gas
liquids sales 114,802 91,463 234,120 172,294
Transportation,
compression and
processing fees 16,516 13,913 29,630 28,912
Condensate and
other 13,914 10,290 27,932 20,559
------ ------ ------ ------
Total revenue 230,051 180,183 496,717 381,261
------- ------- ------- -------
Costs and
expenses:
Cost of natural
gas and
natural gas
liquids (1) 167,613 122,178 377,478 265,497
Transportation
(1) 5,603 5,744 11,279 11,728
Operations and
maintenance 13,230 12,890 25,333 25,562
Depreciation
and
amortization 15,583 13,389 30,784 26,494
General and
administrative 10,900 9,321 21,442 20,046
Taxes other
than income 1,181 727 2,343 1,513
Equity in loss
(earnings)
from
unconsolidated
affiliates 23,632 (2,099) 21,837 (3,583)
------ ------
Total costs and
expenses 237,742 162,150 490,496 347,257
------- ------- ------- -------
Operating
(loss) income (7,691) 18,033 6,221 34,004
Other income
(expense):
Interest and
other income 37 7 44 53
Gain on
retirement of
unsecured debt - - - 3,939
Interest and
other
financing
costs (13,351) (12,001) (28,296) (26,449)
(Loss) income
before income
taxes and
discontinued
operations (21,005) 6,039 (22,031) 11,547
Provision for
income taxes (106) (571) (340) (735)
(Loss) income
from
continuing
operations (21,111) 5,468 (22,371) 10,812
Discontinued
operations,
net of tax - 570 - 1,131
--- --- --- -----
Net (loss)
income $(21,111) $6,038 $(22,371) $11,943
======== ====== ======== =======
Basic net
(loss) income
per common
unit:
(Loss) income
per common
unit from
continuing
operations $(0.32) $0.10 $(0.36) $0.20
Income per
common unit
from
discontinued
operations - 0.01 - 0.02
--- ---- --- ----
Net (loss)
income per
common unit $(0.32) $0.11 $(0.36) $0.22
====== ===== ====== =====
Weighted
average number
of common
units 65,516 54,356 61,941 54,185
Diluted net
(loss) income
per common
unit:
(Loss) income
per common
unit from
continuing
operations $(0.32) $0.09 $(0.36) $0.19
Income per
common unit
from
discontinued
operations - 0.01 - 0.02
--- ---- --- ----
Net (loss)
income per
common unit $(0.32) $0.10 $(0.36) $0.21
====== ===== ====== =====
Weighted
average number
of common
units 65,516 57,946 61,941 57,933
(1) Exclusive of operations and
maintenance and depreciation
and amortization shown separately
below.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months
Ended June 30,
--------------
2010 2009
---- ----
(In thousands)
Cash Flows From Operating
Activities:
Net (loss) income $(22,371) $11,943
Adjustments to reconcile
net (loss) income to net
cash provided by operating
activities:
Depreciation and
amortization 30,784 27,000
Amortization of debt issue
costs 1,790 2,165
Equity in loss (earnings)
from unconsolidated
affiliates 21,837 (3,583)
Distributions from
unconsolidated affiliates 10,993 11,439
Gain on retirement of
unsecured debt - (3,939)
Non-cash gain on risk
management activities, net (1,049) (1,636)
Equity-based compensation 4,688 4,317
Deferred tax provision (98) 373
Other non-cash items (369) 296
Changes in assets and
liabilities:
Accounts receivable 12,231 24,805
Prepayments and other
current assets 2,605 2,080
Risk management activities 6,002 18,479
Accounts payable (3,151) (12,338)
Other current liabilities 1,522 (1,773)
----- ------
Net cash provided by
operating activities 65,414 79,628
------ ------
Cash Flows From Investing
Activities:
Additions to property,
plant and equipment (59,438) (37,380)
Additions to intangible
assets (930) (698)
Acquisitions - (2,840)
Investment in
unconsolidated affiliates (1,538) (2,774)
Distributions from
unconsolidated affiliates 1,997 2,788
Proceeds from the sale of
assets 266 -
Other 523 (995)
---
Net cash used in investing
activities (59,120) (41,899)
-------
Cash Flows From Financing
Activities:
Proceeds from long-term
debt 80,000 50,000
Repayment of long-term
debt (170,000) -
Retirement of unsecured
debt - (14,286)
Distributions to
unitholders (69,430) (62,505)
Proceeds from public
offering of common units,
net of underwriting
discounts and commissions
of $7,223 164,786 -
Equity offering costs (531) -
Proceeds from option
exercises 991 61
Net cash provided by (used
in) financing activities 5,816 (26,730)
-------
Net increase in cash and
cash equivalents 12,110 10,999
Cash and cash equivalents,
beginning of year 44,692 63,684
------ ------
Cash and cash equivalents,
end of period $56,802 $74,683
======= =======
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED BALANCE SHEETS
As of
-----
June 30, December 31,
2010 2009
---- ----
(In thousands, except unit information)
ASSETS
Current assets:
Cash and cash equivalents $56,802 $44,692
Accounts receivable, net 79,267 91,156
Risk management assets 34,506 36,615
Prepayments and other
current assets 2,332 4,937
----- -----
Total current assets 172,907 177,400
------- -------
Property, plant and
equipment, net 890,533 841,323
Intangible assets, net 185,357 190,376
Investment in
unconsolidated affiliates 584,870 618,503
Escrow cash 1,859 1,858
Risk management assets 25,097 15,381
Other assets, net 20,523 22,571
------ ------
Total assets $1,881,146 $1,867,412
========== ==========
LIABILITIES AND MEMBERS'
CAPITAL
Current liabilities:
Accounts payable $116,894 $111,021
Accrued interest 10,645 11,921
Accrued tax liability 456 672
Risk management liabilities 5,169 9,671
Other current liabilities 18,695 9,358
------ -----
Total current liabilities 151,859 142,643
------- -------
Long-term debt (includes
$588 and $628 bond premium
as of June 30, 2010 and
December 31, 2009,
respectively) 762,778 852,818
Deferred tax provision 1,763 1,862
Risk management and other
noncurrent liabilities 6,019 10,063
Members' capital:
Common units, no par value,
65,563,244 and 54,670,029
units issued and
outstanding as of June 30,
2010 and December 31,
2009, respectively 1,157,201 879,504
Class D units, no par
value, 0 and 3,245,817
units issued and
outstanding as of June 30,
2010 and December 31,
2009, respectively - 112,454
Paid-in capital 47,379 42,518
Accumulated deficit (250,675) (158,267)
Accumulated other
comprehensive income
(loss) 4,822 (16,183)
----- -------
958,727 860,026
-------
Total liabilities and
members' capital $1,881,146 $1,867,412
========== ==========
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
OPERATING STATISTICS
(Unaudited)
Three Months Six Months
Ended Ended
June 30, June 30,
-------- --------
2010 2009 2010 2009
---- ---- ---- ----
($ in thousands)
Total segment gross
margin(1) (2) $56,835 $52,261 $107,960 $104,036
Operations and
maintenance
expenses(2) 13,230 12,890 25,333 25,562
Depreciation and
amortization(2) 15,583 13,389 30,784 26,494
General and
administrative
expenses 10,900 9,321 21,442 20,046
Taxes other than
income 1,181 727 2,343 1,513
Equity in loss
(earnings) from
unconsolidated
affiliates(3) (4) (5)
(6) 23,632 (2,099) 21,837 (3,583)
------ ------
Operating (loss)
income(2) (3) (7,691) 18,033 6,221 34,004
Gain on retirement of
unsecured debt - - - 3,939
Interest and other
financing costs, net (13,314) (11,994) (28,252) (26,396)
Provision for income
taxes (106) (571) (340) (735)
Discontinued
operations, net of
tax - 570 - 1,131
--- --- --- -----
Net (loss) income $(21,111) $6,038 $(22,371) $11,943
======== ====== ======== =======
Total segment gross
margin:
Oklahoma(2) $21,821 $17,473 $46,096 $31,773
Texas 31,751 23,320 58,916 43,900
Rocky Mountains(7) 1,148 711 2,251 1,510
----- --- ----- -----
Segment gross
margin(2) 54,720 41,504 107,263 77,183
Corporate and other(8) 2,115 10,757 697 26,853
Total segment gross
margin(1) (2) $56,835 $52,261 $107,960 $104,036
======= ======= ======== ========
Segment gross margin
per unit:
Oklahoma:
Service throughput
($/MMBtu) (2) $0.92 $0.72 $1.00 $0.65
Texas:
Service throughput
($/MMBtu) $0.62 $0.41 $0.57 $0.38
Volumes:
Oklahoma: (9)
Service throughput
(MMBtu/d) (10) 259,972 267,576 254,386 269,389
Plant inlet volumes
(MMBtu/d) 156,204 166,846 154,208 163,532
NGLs produced (Bbls/
d) 16,653 15,981 15,994 15,647
Texas: (11)
Service throughput
(MMBtu/d) (10) 559,876 630,674 571,358 637,565
Pipeline throughput
(MMBtu/d) 327,839 290,005 322,423 296,932
Plant inlet volumes
(MMBtu/d) 469,019 559,597 463,158 558,900
NGLs produced (Bbls/
d) 18,382 18,425 16,869 17,667
Capital expenditures:
Maintenance capital
expenditures $1,649 $3,895 $3,080 $6,046
Expansion capital
expenditures 51,536 14,301 71,942 24,836
------ ------ ------ ------
Total capital
expenditures $53,185 $18,196 $75,022 $30,882
======= ======= ======= =======
Operations and
maintenance expenses:
Oklahoma(2) $5,670 $5,608 $11,103 $11,224
Texas 7,497 7,280 14,066 14,334
Rocky Mountains 63 2 164 4
--- --- --- ---
Total operations and
maintenance
expenses(2) $13,230 $12,890 $25,333 $25,562
======= ======= ======= =======
(1) Total segment gross margin is a non-GAAP financial measure.
For a reconciliation of total segment gross margin to its most directly
comparable GAAP measure of operating income (loss), please read "Non-GAAP
Financial Measures."
(2) Excludes results attributable to Copano's crude oil pipeline
and related assets for the three and six months ended June 30, 2009 as
these amounts are shown under the caption "Discontinued operations."
(3) During the three months ended June 30, 2010, Copano recorded a
$25 million non-cash impairment charge relating to our investment in
Bighorn primarily as a result of a continued weak Rocky Mountains pricing
environment for natural gas, lack of drilling activity in the Wyoming's
Powder River Basin and a downward shift in the Colorado Interstate Gas
forward price curve.
(4) Includes results and volumes associated with Copano's interests
in Bighorn and Fort Union. Combined volumes gathered by Bighorn and Fort
Union were 900,047 MMBtu/d and 980,694 MMBtu/d for the three months ended
June 30, 2010 and 2009, respectively. Combined volumes gathered by Bighorn
and Fort Union were 915,596 MMBtu/d and 993,275 MMBtu/d for the six months ended June 30, 2010 and 2009, respectively.
(5) Includes results and volumes associated with Copano's interest
in Southern Dome. For the three months ended June 30, 2010, plant inlet
volumes for Southern Dome averaged 12,689 MMBtu/d and NGLs produced
averaged 456 Bbls/d. For the three months ended June 30, 2009, plant
inlet volumes for Southern Dome averaged 15,412 MMBtu/d and NGLs produced
averaged 578 Bbls/d. For the six months ended June 30, 2010, plant inlet
volumes for Southern Dome averaged 13,406 MMBtu/d and NGLs produced
averaged 477 Bbls/d. For the six months ended June 30, 2009, plant inlet
volumes for Southern Dome averaged 13,023 MMBtu/d and NGLs produced
averaged 473 Bbls/d.
(6) Includes results and volumes associated with Copano's interest
in Webb Duval. Gross volumes transported by Webb Duval, net of
intercompany volumes, were 54,747 MMBtu/d and 84,452 MMBtu/d for the three
months ended June 30, 2010 and 2009, respectively. Gross volumes
transported by Webb Duval, net of intercompany volumes, were
57,405 MMBtu/d and 86,584 MMBtu/d for the six months ended June 30,
2010 and 2009, respectively.
(7) 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 and
volumes transported using Copano's firm capacity agreements with WIC and
compressor rental services provided to Bighorn. Excludes results and
volumes associated with Copano's interests in Bighorn and Fort Union.
(8) Corporate and other includes results attributable to Copano's
commodity risk management activities.
(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 June 30, 2010, plant inlet volumes averaged
119,030 MMBtu/d and NGLs produced averaged 13,289 Bbls/d for plants owned
by the Oklahoma segment. For the three months ended June 30, 2009, plant
inlet volumes averaged 128,390 MMBtu/d and NGLs produced averaged 12,956
Bbls/d for plants owned by the Oklahoma segment. For the six months ended
June 30, 2010, plant inlet volumes averaged 118,320 MMBtu/d and NGLs
produced averaged 12,881 Bbls/d for plants owned by the Oklahoma segment.
For the six months ended June 30, 2009, plant inlet volumes averaged
125,661 MMBtu/d and NGLs produced averaged 12,747 Bbls/d for plants owned
by the Oklahoma segment. Excludes volumes associated with Copano's
interest in Southern Dome.
(10) "Service throughput" means the volume of natural gas delivered
to Copano's wholly owned processing plants by third-party pipelines plus
Copano's "pipeline throughput," which is the volume of natural gas
transported or gathered through Copano's pipelines.
(11) 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 461,880 MMBtu/d and NGLs produced averaged
17,864 Bbls/d for the three months ended June 30, 2010 for plants
owned by the Texas segment. Plant inlet volumes averaged 539,946
MMBtu/d and NGLs produced averaged 16,759 Bbls/d for the three months
ended June 30, 2009 for plants owned by the Texas segment. Plant inlet
volumes averaged 456,180 MMBtu/d and NGLs produced averaged 16,366 Bbls/d
for the six months ended June 30, 2010 for plants owned by the Texas
segment. Plant inlet volumes averaged 537,528 MMBtu/d and NGLs produced
averaged 15,920 Bbls/d for the six months ended June 30, 2009 for plants
owned by the Texas segment. Excludes volumes associated with Copano's
interest in Webb Duval.
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 risk
management activities, which are included in corporate and other) to
the GAAP financial measure of operating income (loss), (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 (in thousands).
Three Months Six Months
Ended Ended
June 30, June 30,
-------- -------
2010 2009 2010 2009
---- ---- ---- ----
($ in thousands)
Reconciliation of total
segment gross margin to
operating (loss)
income:
Operating (loss) income $(7,691) $18,033 $6,221 $34,004
Add: Operations and
maintenance expenses 13,230 12,890 25,333 25,562
Depreciation and
amortization 15,583 13,389 30,784 26,494
General and
administrative expenses 10,900 9,321 21,442 20,046
Taxes other than income 1,181 727 2,343 1,513
Equity in loss
(earnings) from
unconsolidated
affiliates 23,632 (2,099) 21,837 (3,583)
------ ------
Total segment gross
margin $56,835 $52,261 $107,960 $104,036
======= ======= ======== ========
Reconciliation of EBITDA
and adjusted EBITDA to
net (loss) income:
Net (loss) income $(21,111) $6,038 $(22,371) $11,943
Add: Depreciation and
amortization(1) 15,583 13,835 30,784 27,000
Interest and other
financing costs 13,351 12,001 28,296 26,449
Provision for income
taxes 106 571 340 735
--- --- --- ---
EBITDA 7,929 32,445 37,049 66,127
Add: Amortization of
difference between the
carried investment and
the underlying equity
in net assets of equity
investments and
impairment 29,645 4,785 34,290 9,603
Copano's share of
depreciation and
amortization included
in equity in earnings
from unconsolidated
affiliates 1,603 1,776 3,140 3,333
Copano's share of
interest and other
financing costs
incurred by equity
method investments 494 (30) 865 478
--- --- ---
Adjusted EBITDA $39,671 $38,976 $75,344 $79,541
======= ======= ======= =======
Reconciliation of EBITDA
and adjusted EBITDA to
cash flows from
operating activities:
Cash flow provided by
operating activities $36,250 $44,230 $65,414 $79,628
Add: Cash paid for
interest and other
financing costs 12,455 11,106 26,505 24,284
Equity in (loss)
earnings from
unconsolidated
affiliates (23,632) 2,099 (21,837) 3,583
Distributions from
unconsolidated
affiliates (5,228) (6,068) (10,993) (11,439)
Risk management
activities (5,405) (9,291) (6,002) (18,479)
Changes in working
capital and other (6,511) (9,631) (16,038) (11,450)
-------
EBITDA 7,929 32,445 37,049 66,127
Add: Amortization of
difference between the
carried investment and
the underlying equity
in net assets of equity
investments and
impairment 29,645 4,785 34,290 9,603
Copano's share of
depreciation and
amortization included
in equity in earnings
from unconsolidated
affiliates 1,603 1,776 3,140 3,333
Copano's share of
interest and other
financing costs
incurred by equity
method investments 494 (30) 865 478
--- --- ---
Adjusted EBITDA $39,671 $38,976 $75,344 $79,541
======= ======= ======= =======
Reconciliation of net
(loss) income to total
distributable cash
flow:
Net (loss) income $(21,111) $6,038 $(22,371) $11,943
Add: Depreciation and
amortization(1) 15,583 13,835 30,784 27,000
Amortization of
commodity derivative
options 8,070 9,291 16,048 18,479
Amortization of debt
issue costs 895 895 1,790 2,165
Equity-based
compensation 2,686 2,296 5,401 4,255
Distributions from
unconsolidated
affiliates 6,254 7,296 12,991 14,227
Unrealized loss
associated with line
fill contributions and
gas imbalances 756 361 2,338 527
Unrealized gain on
derivatives (1,582) (1,396) (1,049) (1,636)
Deferred taxes and other (68) 325 (369) 672
Less: Equity in loss
(earnings) from
unconsolidated
affiliates 23,632 (2,099) 21,837 (3,583)
Maintenance capital
expenditures (1,649) (3,895) (3,080) (6,046)
------ ------ ------
Total distributable cash
flow(2) $33,466 $32,947 $64,320 $68,003
======= ======= ======= =======
Actual quarterly
distribution ("AQD") $38,295 $31,869
======= =======
Total distributable cash
flow coverage of AQD 87% 103%
=== ===
(1) Includes depreciation and amortization related to the
discontinued operations.
(2) Prior to any retained cash reserves established by Copano's
Board of Directors.
SOURCE Copano Energy, L.L.C.
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